UA74818C2 - Method and apparatus for intensification of multiple intervals of formation - Google Patents

Abstract

The invention provides an apparatus and method for perforating and treating multiple intervals of one or more subterranean formations (86) intersected by a wellbore by deploying a bottom-hole assembly having a perforating device (134) and at least one sealing mechanism (120) within said wellbore. The perforating device (134) is used to perforate the first interval to be treated. Then the bottom-hole assembly is positioned within the wellbore such that the sealing mechanism (120), when actuated, establishes a hydraulic seal in the wellbore to positively force fluid to enter the perforations (230, 231) corresponding to the first interval to be treated. A treating fluid is then pumped down the wellbore and into the perforations (230, 231) created in the perforated interval. The sealing mechanism (120) is released, and the steps are then repeated for as many intervals as desired, without removing the bottom hole assembly from said wellbore.

Description

Description of the invention

This invention relates to the field of perforation and technological processing (preparation) of underground 9 geological formations to increase the extraction of oil and gas from them. More specifically, the present invention relates to a device and a method for perforating and processing multiple intervals without the need to remove the equipment from the wellbore between operations of the method.

In the event that the hydrocarbon-bearing underground productive formation does not have sufficient permeability or throughput to ensure the flow of hydrocarbons to the surface in economically beneficial 70 quantities or at optimal rates, hydraulic fracturing or chemical (usually acid) intensification is often used to increase throughput ( excitation). A wellbore that penetrates a subterranean formation usually contains metal tubing (casing) cemented into the original borehole. Holes (perforations) pass through the casing and the cement coating surrounding the casing to allow the flow of hydrocarbons into the wellbore and, if necessary, to allow the flow of treatment fluids from the wellbore into the formation.

Hydraulic fracturing consists in injecting (injecting) fluids (usually a viscous shear thinning agent, non-Newtonian gels or emulsions) into the formation at such high pressure and velocities that the formation rock cracks and forms a flat, usually vertical crack ( or grid of cracks) in many ways similar to the crack that develops in a log when a wedge is inserted into it. Granular proppant material, such as sand, ceramic balls, or other materials, is usually injected with the final portion of fracturing fluid to keep the fracture(s) open after depressurization. The increased throughput from the formation is the result of facilitating the path of movement of fluids between the grains of the wedging material in the crack (cracks). In the case of chemical treatments for intensification, the permeability is improved due to the dissolution of materials in the formation or due to other changes in the properties of the formation. Gee)

The application of hydraulic fracturing as described above is a common part of oil production operations, which are used for individual defined zones of up to approximately 60 meters (200 feet) of underground formation of great vertical thickness. In the event that hydraulic fracturing of multiple reservoirs, a layered reservoir, or a very thick hydrocarbon-bearing formation (with a thickness of more than approximately 60 meters) is conducted, then alternative processing technologies are required to ensure the processing of the entire given "- zone." Methods used to improve processing are commonly known in the oil industry as diversion methods. co

In the case when multiple hydrocarbon-bearing zones are excited by hydraulic fracturing or chemical intensification treatments, economic and technical gains are realized through the use of multiple treatment levels that can be separated (or separated) by various means. , containing mechanical devices such as packer plugs, packers, downhole valves, slip couplings, and baffle and plug combinations; sealing balls, powder materials such as sand, ceramic material, wedging filler, salt, paraffins, resins or other compounds; or using "alternative fluids, such as viscosity-enhancing fluids, C 50 gelling fluids, foam materials, or other chemically generated fluids; or due to the use of intake restriction methods. These and all other similar methods and devices that temporarily block the flow of fluids into or out of a given set of perforations will be referred to as "rejection agents".

In the case of deviation, for example, with the help of a mechanical packer plug, first of all, the deepest interval is perforated and a crack (fault) is excited, and then this interval is usually isolated due to the packer plug, which is installed with the help of a melting rope, and the process is repeated for the next interval from above. If "" assume 10 specified perforation intervals, then processing 300 meters (1,000 feet) of the formation in this manner will typically require ten processing operations, carried out over a period of time from 10 days to two hundred weeks, and it is necessary to carry out not only multiple treatments to create cracks , but also to carry out - 20 multiple perforations and operations of moving the packer plug. At the end of the treatment process, a wellbore cleaning operation is required to remove the packer plugs and start the spoil from the well. The main advantage of using packer plugs and other mechanical deflection agents is the high confidence that the entire given area is treated. The main disadvantages are the high processing cost associated with the multiple operations of entering the wellbore and withdrawing from it, and the risk of complications associated with the presence of 25 multiple operations carried out in the well. For example, a packer plug can get stuck in the casing and

GF) then it is necessary to drill it, which leads to large costs. Another drawback is that the required wellbore cleaning operation may damage some intervals with successfully formed cracks.

One alternative to the use of packer plugs is to fill the section of the wellbore connected at 60 intervals with the newly formed fractures with fracturing sand, commonly known as Ripe Easyap technology. The column of sand in the wellbore essentially plugs the interval with already formed cracks and allows independent perforation and formation of cracks in the next interval. The first advantage of this is the elimination of the problems and risks associated with packer plugs. Disadvantages are related to the fact that the plug (pillar) of sand does not provide perfect hydraulic sealing and it is difficult to remove it from the wellbore at the end of all crack excitation operations. Unless the wellbore fluid flow is strong enough to carry sand from the wellbore, the wellbore may still need to be cleaned with a workover rig or coiled tubing unit. As before, additional operations in the wellbore increase costs, mechanical risks and

Signs of damage to intervals with formed cracks.

Another method of rejection involves the use of powdered materials (granular solids) that are introduced into the processing fluid to promote rejection. When the fluid is pumped, the particles enter the perforations, and a temporary block is formed in the fluid receiving zone, if the flow contains a sufficiently high concentration of particles. The resulting flow restriction leads to the deviation of the fluid to other zones. After processing, the powder material is removed with the help of the fluid medium of the formation, which is obtained or with the help of the pumped washing fluid due to the carryover by the fluid medium or due to dissolution. Among the common powdery deflecting materials available are benzoic acid, naphthalene, rock salt (sodium chloride), resins, paraffins, and polymers. Alternatively, as powder means of deflection can be used /5 Sand, wedging agent and ceramic materials. Other special powder materials that are deposited and formed during processing can be used.

Another method of rejection involves the use of high-viscosity fluids, viscous gels or foam materials as rejection agents. This method involves injecting a deflecting fluid through and/or into the perforated interval. These fluids are designed to temporarily block the flow to the perforations by increasing the viscosity or decreasing the relative permeability of the formation; and these fluids are designed so that at a desired time the medium breaks down, degrades or dissolves (with or without the addition of chemicals or other additives to initiate such breakdown or dissolution) so that flow can be restored in or out of the perforations . These fluids can be used to reject matrix chemical treatments of intensification and chemical treatments for the formation of cracks. Sometimes, powdered deflection agents and/or sealing balls are introduced into these fluids to enhance deflection. and)

Another possible method is the method of limited input deviation, which involves perforating the entire given zone of the formation to be processed with a very small number of perforations, usually of small diameter, in such a way that the pressure loss through these perforations during the injection of the sozo contributes to obtaining high internal pressure in the wellbore. The internal pressure in the wellbore is chosen high enough to cause simultaneous formation of cracks in all perforated intervals. If the pressure is very low, cracks will form only in the weakest parts of the formation. The first advantage of limited input deflection is that there are no obstructions inside the casing, such as packer plugs or sand, which cause problems later. The disadvantage is that the limited « c5 Input fracturing often does not work well at large intervals, because the resulting fracture is often a very narrow MU (the proppant cannot be completely pumped through the narrow fracture and remains in the wellbore), and the initial high pressure in the wellbore may disappear. When sand is injected, the diameter of the perforations is often quickly eroded and increases, and the increased size of the perforations reduces the internal pressure in the wellbore. The final result of this can be the lack of excitation of all « 0 specified zones. Additional concern is caused by the potential limitation of throughput in the wellbore due to the small number of perforations.

Some of the problems associated with the impossibility of exciting the entire given zone or with the use of mechanical;" methods that require multiple wellbore operations and wellbore injections, which create high risk and lead to high costs, as described above, can be solved by using limited concentrated perforated intervals deflected by -I sealing balls . The zone to be processed can be divided into subzones with perforations approximately in the center of each such subzone, or the subzones can be selected based on the analysis of the formation, in which the specified desired locations of the cracks are found. After that, pumping (pumping) in the level can be carried out

Go! (sections) of the crack, with deviation by means of sealing balls at the end of each level. In particular, 300 meters (1,000 feet) of a large formation can be divided into 10 subzones of roughly 30 meters (about 100 feet) each. In the center of each 30-meter (100-foot) subzone, 10 perforations can be drilled at a density of 3 s holes per meter (one hole per foot) of casing string. After that, a fluid with a wedging agent is injected into the crack level, and then 10 or more sealing balls are injected, at least one into each open perforation in one set of perforations or in one interval. The process is repeated until all sets of perforations have cracks. Such a system is described in more detail in the patent |ISSA Mo5890536 dated April 6, 1999|.

F) Historically, all zones to be processed in a specific process operation, in which sealing balls are used as a diversion agent, are perforated before injection of fluids for formation treatment, and sealing balls are used to divert fluids for drilling. from zones with already formed cracks or from zones that are otherwise able to receive a large part of the fluid flow, while other zones receive a smaller part of the fluid or none at all until the sealing balls are released. Processing and compaction is theoretically carried out zone by zone depending on the relative fracture pressure (rupture) or on permeability, however, problems often arise due to the premature entry of balls into one or more open perforations outside the specified interval, and with 65 two or more zones , which are processed simultaneously. Moreover, this technology assumes that each perforation interval or subzone will fail and crack at quite different pressures, so that each treatment level will be used for only one set of perforations.

The primary advantages of sealing ball deflection are low costs and low risk of mechanical problems. Costs are low because the process can usually be completed in one continuous operation, usually within a few hours of a day. Only the sealing balls remain in the wellbore, which will either come out together with the extracted hydrocarbons, or fall to the bottom of the well, in an area called a square pit. The first disadvantage is the lack of confidence in the simultaneous formation of cracks in only one set of perforations, when the exact number of sealing balls falls at the end of each processing level. In fact, the advantages of the process depend on a single crack level entering the 7/0 formation through only one set of perforations, with all other open perforations remaining largely unused during this processing stage. Other disadvantages are the lack of certainty that all perforated intervals will be processed, and that the sequence of processing specified intervals will be preserved during processing operations. In the case where the treatment order of a zone is unknown or uncontrollable, it is not possible to ensure the treatment of each individual zone or to optimally design the individual treatment level of intensification for a given zone. In some cases, it is not possible to carry out such processing control, in which individual zones are processed at a single processing level.

In order to overcome some of the indicated disadvantages that may occur during intensification treatments, when a number of zones are perforated before the injection of fluids for formation treatment, an alternative method of mechanical deviation has already been developed, which involves the use of an intensification system with 2o coiled pipes, which allows successive excitation of a number of intervals during their separate processing. As with conventional deflection using a sealing ball, all intervals to be processed are perforated prior to the injection of fluids to process the formation. The coiled tubing is then run through the wellbore using a mechanical deflection device similar to a double-sided packer attached to the end of the tubing. This deflection means, when properly installed and actuated through the perforations, provides hydraulic isolation above and below said deflection means.

After installation and actuation of the deflection means to isolate the deepest set of perforations, liquid i) intensification medium is pumped down into the coiled tubes, which exits through the channels provided in the deflection means between the upper and lower sealing elements. After the completion of the first stage of processing, the sealing elements provided on the deflection means are disconnected or disconnected and the coiled tubes are pulled upwards to install the deflection means across the second set of perforations from the bottom, and the process is continued until all the specified intervals have been excited , or the process (87 is terminated due to operational failure. so

This type of coiled tubing intensification device and associated method is used for hydraulic fracturing of multiple zones in wells at depths up to approximately 8,000 feet. However, at this time, various technical obstacles, including frictional pressure losses, damage to sealing elements, depth control, flow rate, and potential erosion of coiled tubing, limit the use of this device in deeper wells.

Excessive frictional pressure is created when pumping fluids for intensification, especially with wedging fillers, and/or fluids that have high viscosity at high speeds "through long lengths of coiled tubing. Depending on the length and diameter of the coiled pipes, the viscosity of the medium flowing from c, the maximum permissible operating pressure of the equipment on the surface and the injection speed can be

And limited to just a few barrels per minute; however, this, depending on the characteristics of a specific and? of the underground formation may not allow effective injection of a wedging agent during hydraulic fracturing or effective dissolution of formation materials during acid intensification.

Erosive wear of the coiled tubes can also create a problem when injecting fluid with -I wedging filler down into the coiled tubes at high velocity, including into the section of these tubes that remains wound on the drum at the surface. The risk of erosion increases when the fluid media with the wedging filler encounters the "continuous bend" section of the coiled tubing, wound on the drum on the surface.

Most sealing elements (eg, cuff-type sealing elements) currently used in coiled tubing intensification operations described above can have sealing problems or seal failures in deeper wells because the sealing elements pass through a large number of perforations at high pressures. borehole temperatures characteristic of deeper wells.

Since the sealing element moves in contact with the pipe wall or with minimal clearance from it, two rough internal surfaces of the pipe and/or perforation burrs can damage the sealing element. Sealing elements currently found in double-sided packer-type deflection devices are made of (F, elastomers) which may not withstand the high temperatures often found in deeper wells. type, as a rule, is approximately from 15 to

30 feet per minute when moving down the wellbore and from 30 to 60 feet per minute when moving bo up the wellbore. For example, moving at the slowest speed, it would take approximately 13 hours to reach a depth of 12,000 feet before impacting the formation. Taking into account the safety instructions for working at night, when moving at low speed, it will take many days to complete the intensification operation. If problems arise during the technological operation, lifting the equipment from the well and lowering it into it can be very expensive, as it takes a lot of time due to low running 65 SPEEDS.

Controlling the depth of the coiled pipe system and double-spanning packer-type deflection means also becomes more difficult as depth increases, and correctly setting the deflection means at the required depth for a successful intensification operation can be difficult. This problem is solved by making perforations before inserting the coiled pipes into the well. When performing the perforation operation, another depth measuring device is used (usually the casing joint location system), which is different from the one used in the coiled pipe system.

In addition, the coiled tubing method described above requires that all perforations be made in the wellbore by performing a separate perforating operation prior to the intensification pumping operation. Having multiple sets of perforations open above the deflection means can create 70 operational difficulties. For example, if the wedging fracture from the current zone grows vertically and/or if there is poor quality cement behind the pipe, then the fracture may cross a set of perforations above the diverter so that the wedging agent can flow back into the wellbore from above the diverter, preventing further movement the indicated means. In addition, circulation operations may be hindered if multiple sets of perforations are open above the deflection means. For example, if the /5 Circulation pressure exceeds the fracture pressure associated with perforations open above the diversion means, circulation may not be maintained and circulating fluid may be inadvertently lost to the formation.

A similar type of intensification operation can also be carried out using composite pipes and well repair equipment instead of a coiled pipe system. The use of a deflection device, 2o deployed on component pipes, can allow the use of larger diameter pipes to reduce frictional pressure losses and increase injection speeds. In this case, the danger of erosion and violation of the integrity of the pipes is reduced compared to coiled pipes, since component pipes with a greater wall thickness can be used, while the component pipes will not undergo plastic deformation when moving in the wellbore. However, the use of this approach can lead to an increase in the time of the operation and its cost due to the lower speeds of the pipe movement compared to coiled pipes.

To overcome some of the limitations associated with completion (well completion) operations, which i) require multiple descents and ascents of equipment into and out of the wellbore, for perforating and exciting underground formations, "single descent and ascent" methods are proposed column of the well tool, which allows to conduct the excitation of the crack in the zones in combination with perforation. In particular, these methods use operations that minimize the number of necessary operations in the wellbore and the time required to complete such operations, as a result of which the cost of processing - intensification is reduced. These proposals include the following: 1) the presence of a suspension of sand in the wellbore when perforating with non-equilibrium pressure, 2) dumping the sand from the bucket simultaneously with the ignition of the charges for perforating, and 3) enclosing the sand in a separate container with explosive release. All these proposals provide only minimal penetration of the fracture into the wellbore environment and are not adapted to the needs of the multi-stage hydraulic fracturing described here.

According to the above, there is a need to develop an improved method and device for individual processing of each of the multiple intervals of the underground formation into which the wellbore passes, while preserving the economic benefits of multi-stage processing. There is also a need for methods and devices that economically reduce the risks inherent in intensification treatment options currently available for hydrocarbon-bearing formations with multiple reservoirs or layered reservoirs, or at thicknesses approximately greater than 60 meters (200 feet ), when performing optimal processing using mechanical ;" a deflection agent that directs the processing levels to the desired location.

In accordance with this invention, a device and a method for perforating and processing a plurality of intervals of one or more underground formations intersected by a wellbore are proposed. -I The device includes a means of deployment (for example, coiled pipes, component pipes, power line, lead line, well tractor (tractor), etc.) with downhole equipment, which includes at least a device for perforating and a mechanical sealing mechanism, which is established many times, which can be brought to

Go! acting independently by means of one or more means of transmitting signals (for example, by means of 5p electronic signals transmitted by a conductive line of communication; hydraulic signals transmitted by pipes through the annular space and component hoses, by means of tensile or compressive loads, with the help of radio communication; with the help of a fiber-optic communication line; with the help of computer systems located on the slaughter equipment, etc.).

The proposed method includes the operations of deploying the downhole equipment in the wellbore with the use of deployment means, which can be a column of pump-compressor pipes, a cable or a well tractor. The perforating device is installed adjacent to the interval to be perforated (F) and is used to perforate the specified interval. The drilling equipment is installed in the wellbore using deployment means, and the sealing mechanism is actuated to create a hydraulic seal that directs the injected fluid downward into the boreholes for entering the perforated interval, after which the sealing mechanism is released (disabled).

The process can then be repeated without pulling the drilling equipment from the wellbore for at least one additional interval of one or more underground formations.

The means of deployment can be a string of pump-compressor pipes, which includes coiled pipes or standard component pipes, a conductive line of communication, a wire rope or a cable. Instead of pipes or cable, the deployment means 65 may be a tractor system associated with the bottoming equipment. The tractor system can be a self-propelled system with computer control, which has a control unit on board, so that there is no need to connect a cable or pipes to it to control and actuate the slaughtering equipment and/or tractor system. Alternatively, the tractor system may receive control and power through the wires or pipes of the composite hose (hose cable), with the tractor system and downhole equipment being controlled and actuated by signals transmitted to the well using the composite hose.

There are many different versions of the invention depending on the means of suspension and specific components of the slaughter equipment.

In a first embodiment of the invention, when the means of deployment is a string of pump-compressor pipes, immediately after the interval is perforated, the downhole equipment can be moved and the sealing mechanism 70 is activated to create a hydraulic seal below the perforated interval. The treatment fluid can then be pumped down into the annular space between the tubing string and the wellbore and into the perforated interval. A second treatment fluid, such as nitrogen, may also be pumped through the tubing string at the same time as the first treatment fluid down into the annular space between the tubing string and the wellbore.

In the second embodiment, when the suspension means is a string of pump-compressor pipes, immediately after the interval is perforated, the downhole equipment can be moved and the sealing mechanism is activated to create a hydraulic seal above the perforated interval. The treatment fluid can then be pumped down through the tubing string and into the perforated interval.

In a third option, where the deployment means is a string of pump-compressor pipes, the downhole equipment may be moved and the sealing mechanism actuated to create a hydraulic seal above and below the perforated interval (in this case, the sealing mechanism includes two sealing elements offset by a sufficient distance from each other to span the perforated interval on both sides). In the third variant, the fluid for processing can be pumped down through the column of pump-compressor pipes itself, through the channel of the hydraulic system, located between the two sealing elements of the sealing mechanism, and into the perforated interval.

In a fourth embodiment, when the downhole equipment is deployed in the wellbore using i) a wireline, wire rope or cable, the downhole equipment can be moved and the sealing mechanism actuated to create a hydraulic seal below the perforated interval to be treated, and the treatment fluid can be pumped down into the annular space between the wireline, wire rope or cable and the wellbore.

In the fifth variant of the implementation of the invention, the composite hose is deployed as an additional means of actuation - a component of the slaughter equipment. In the most general case, the composition hose is in the form of a small diameter pipe or a plurality of pipes to provide hydraulic communication with the downhole equipment components, and/or the composition hose may be in the form of a cable or a plurality of cables to provide electrical or electro-optical communication with the components slaughter equipment. Cha

In a sixth embodiment of the invention, when the deployment means is a tractor system associated with the bottoming equipment, the bottoming equipment may be moved and the sealing mechanism actuated to create a hydraulic seal below the perforated interval. The treatment fluid can then be pumped down the wellbore and into the perforated interval. "

In the seventh embodiment of the invention, abrasive fluid jet cutting technology is used for perforating, and the downhole equipment is suspended by means of pipes, so that the downhole equipment can be moved and the compaction mechanism is activated to create;" hydraulic seal below the perforated interval. The treatment fluid can then be pumped down into the annular space between the pipes and the wellbore.

One of the primary advantages of the proposed device and method is that the downhole equipment, including the sealing mechanism and the perforating device, does not need to be removed from the well prior to processing with a processing fluid and between processing multiple zones or intervals of the formation . Another primary advantage of the proposed device and method is that each level o (stage) of processing is deflected using a mechanical deflection agent, so that an accurate

Controlling the processing deviation process and each zone can be optimally excited. As a result, a significant reduction in cost is obtained due to the reduction of the time required for perforating and processing a set of intervals in the wellbore. In addition, in this case, an increase in throughput is achieved due to the use of a mechanical deviation agent, which provides deviation processing with precise control when exciting a set of formation intervals in the wellbore. The proposed device and method have two significant economic advantages in comparison with existing methods and equipment, since the device and method according to this invention allow perforating and exciting multiple zones at (Ф, a single entrance to the wellbore, with the subsequent removal of the drilling equipment, which plays the dual role of a mechanical deflection agent and a perforating device.

The foregoing and other characteristics and advantages of the invention will become more apparent from the following detailed description taken with reference to the accompanying drawings, in which the following is shown.

Figure 1 depicts a possible typical example of a wellbore configuration with peripheral equipment that may be used to support downhole equipment used in accordance with the present invention. Fig.1 also shows a typical example of storage of downhole equipment in wellbores with surface wedges (wedge grabs), and specified wellbores can be used 65 to store spare parts or emergency downhole equipment.

Fig. 2 depicts the first version of the downhole equipment, which is deployed using coiled pipes in a non-perforated wellbore and installed at the depth of the perforation location using the first set of charges that are selectively ignited for perforation. Fig. 2 further depicts that the slaughtering equipment includes a device for perforating, an inflatable packer that is installed multiple times,

Multi-set axial wedge gripper and auxiliary components.

Fig. 3 shows the downhole equipment, coiled pipes and wellbore Fig. 2 after the ignition of the first set of charges, which are selectively ignited for perforation, which leads to the appearance of perforations (holes) in the production casing and in the cement casing, which pass into the first zone of the formation , in such a way that a hydraulic connection is established between the wellbore and the first zone of the formation. 70 Fig. 4 shows the bottom-hole equipment, coiled pipes and the wellbore of Fig. C after rearranging the bottom-hole equipment and exciting the first zone of the formation with the help of the first level of a multi-stage hydraulic fracturing operation, when the first level of the fracturing operation is carried out through the annular space of the wellbore of the well existing between the coiled pipes and the production casing. In Figure 4, the sealing mechanism is shown in a non-operating state, because only for the purpose of explaining the invention, it is assumed that there are no perforations other than those associated with the first zone, and therefore, insulation is not required for processing the first zone.

Fig. 5 shows the downhole equipment, coiled pipes and the wellbore Fig. 4 after rearranging the downhole equipment and igniting the second set of charges, which are selectively ignited for perforation, which leads to the appearance of perforations in the production casing and in the cement shell, which pass into the second zone formation, in such a way that a hydraulic connection is established between the wellbore and the second zone of the formation.

Fig. 6 shows the downhole equipment, the coiled pipes and the wellbore Fig. 5 after repositioning the downhole equipment to a significant distance below the deepest perforation of the second set of perforations, with the possibility of slightly moving the downhole equipment up to install the axial wedge grab, which is installed many times at maintaining the location of the circulation channel below the lowest perforation of the second set of perforations. and)

Fig. 7 depicts the downhole equipment, coiled tubing and wellbore of Fig. b after activation of the mechanical wedge gripper, which is installed multiple times to create resistance to the downward axial movement while providing the position of the inflatable packer, which is installed multiple times and with the mechanical wedge gripper. , which is installed many times between the first zone and the second zone of perforations.

Fig. 8 shows the downhole equipment, coiled pipes and the wellbore Fig. 7 after activation of the multipack inflatable packer to create a flow barrier between the wellbore section immediately above the multipack inflatable packer and the wellbore section directly below the inflatable packer, which is installed many times. -

Fig. 9 shows the downhole equipment, coiled pipes and the wellbore Fig. 8 after the excitation of the second zone of the formation using the second level of multi-stage hydraulic fracturing, and the second level of hydraulic fracturing is injected in the annular space of the wellbore existing between the coiled pipes and the operational casing string.

Fig. 10 shows the bottom-hole equipment, coiled pipes and the wellbore Fig. 9 after deactivation of the inflatable packer, which is installed many times, due to which the pressure transfer between 7-3) with the section of the wellbore immediately above the inflatable packer, which is installed many times, is again established times and

And a section of the wellbore immediately below the multi-set inflatable packer, while the multi-set mechanical wedge gripper is still energized and continues to prevent the coiled tubing and downhole equipment from moving down the wellbore.

Fig. 11 shows a modified slaughtering equipment similar to the slaughtering equipment shown in Figs. 2-4-I and Fig. 5-10, but with the addition of a mechanical plug, which is installed using a system of installation of charges that are selectively ignited, located below the column of firing perforators. Fig. 11 also shows the coiled ve pipes and the wellbore Fig. 10 after the additional third perforation and carrying out the excitation operation

Go! cracks Fig. 11 shows only the second and third cracks and the corresponding sets of perforations. Fig. 11 shows a modified downhole equipment suspended by means of coiled pipes in such a way that the location of the packer plug is above the last perforated interval and below the next interval to be perforated.

Fig. 12 shows the bottom-hole equipment, coiled pipes and wellbore Fig. 11 after installing a mechanical plug in the well using selective ignition of the charge, after moving the bottom-hole equipment and igniting the first set of charges that are selectively ignited for perforation, as a result of which perforations are obtained in the operational in the casing and in the cement shell, passing into the fourth zone

F) formation, in such a way that a hydraulic connection is established between the wellbore and the fourth zone of the formation.

Fig. 13 shows the second embodiment of the invention, in which the means of suspension is a column of pump-compressor drill pipes, and immediately after perforating the interval, the downhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal above the perforated interval. The treatment fluid can then be pumped down the tubing string and into the perforated interval.

Fig. 14 shows a third embodiment of the invention, in which the means of suspension is a column of pump-compressor pipes 65, and the downhole equipment can be moved and the sealing mechanism is activated to create a hydraulic seal above and below the perforated interval (in this case, the sealing mechanism contains two sealing elements offset from each other by a sufficient distance to span both sides of the perforated interval), in this variant, the processing fluid can be pumped down through the column of pump-compressor pipes itself, through the channel of the hydraulic system located between the two sealing elements of the sealing mechanism, and in the perforated interval.

Fig. 15 shows the fourth embodiment of the invention, in which the drilling equipment is suspended in the wellbore using a wire line (or wire rope or cable); the downhole equipment is moved and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval to be treated, after which the treatment fluid is pumped down into the 70 annular space between the wireline, wire rope or cable and the wellbore.

Figures 16 and 17 show a fifth embodiment of the invention, in which a composite hose is used, deployed inside the pipes used as a means of deployment, to actuate the sealing mechanism, which is installed many times.

Fig. 18 shows a sixth embodiment of the invention, in which a tractor system is used, which is connected to /5 downhole equipment, with which the downhole equipment is moved and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval, after which the fluid medium for treatment is pumped down into the wellbore and into the perforated interval.

Fig. 19 shows the seventh embodiment of the invention, in which the abrasive or erosive fluid jet cutting technology is used in the perforating device, the drilling equipment is suspended in the 2o wellbore using component pipes and includes a mechanical set for compression, a packer that is installed many times, a device for perforating with an abrasive or erosive sharp jet of fluid, a casing joint locator and auxiliary components. In this variant, perforations are created by pumping an abrasive fluid down into the component of the pipe, which exits through a jet perforator located in the downhole equipment, in such a way that a high-pressure and high-speed jet of abrasive or erosive fluid is created, which is used to create perforations in the production casing and in the cement shell, thanks to which i) a hydraulic connection is established between the wellbore and the desired interval of the formation. After installing the packer, which is installed many times lower than the zone to be excited, the fluid for treatment can be pumped down into the annular space located between the column of pump-compressor pipes and the operational casing column.

Further, this invention will be described with reference to its preferred variants, but it should be borne in mind that specific variants and specific uses of the invention are given only for its better understanding and are not of a limiting nature. On the contrary, the description of the invention is intended to cover all alternatives, modifications and equivalents that are included in the scope of the invention, defined in accordance with the attached formula "C5 of the invention." Cha

In accordance with the present invention, there is provided a new method, a new system and a new device for perforating and exciting a plurality of formation intervals, which allow each individual zone to be treated with an individual level of treatment, which eliminates or minimizes the problems associated with this time by methods of intensification using coiled pipes or composite pipes, and, therefore, "creates significant economic and technical advantages in comparison with existing methods. More precisely, the invention proposes to carry out the suspension of drilling equipment in the wellbore for individual and sequential perforation and treatment of each of the set of desired zones, with multi-stage intensification and deploying a mechanical compaction mechanism to ensure a deviation set multiple times for each individual processing level being monitored. For the purposes of this invention, the term "wellbore" is to be understood as a system that includes -I below-ground well sealing components and all below-ground sealed equipment, such as the wellhead, the winding drum parts, the blowout preventer and the oiler. o The new device includes a means of deployment (for example, coiled pipes, component pipes, 5p electric wire, a conducting line, a tractor system, etc.), and the bottom-hole equipment includes, at a minimum, - a device for perforating and a mechanical sealing mechanism, which is repeatedly installed, which can be independently actuated from the surface by one or more means of generating signals (for example, by means of electrical signals transmitted by a wireline, hydraulic signals transmitted by pipes through the annulus and component hoses, with the help of tensile or compression loads; with the help of radio communication, with the help of a fiber-optic communication line, etc.), while the downhole equipment is designed taking into account the existing conditions in the wellbore and the character (F, load. ka In the most general sense, the term "killing equipment" is used here to denote a set of components, which includes, at least, a device for perforation and the sealing mechanism, which can be installed many times. Additional components may include (but are not limited to) fishing necks, shear pin adapters, flushing fixtures, circulation duct adapters, hydraulic duct adapters, pressure equalization duct adapters, temperature sensors, pressure sensors, lead line adapters, mechanical wedge gripper , which can be installed multiple times, casing joint locators, centralizer adapters and/or coupling adapters that may also be used in the downhole equipment to facilitate other possible auxiliary or service operations and measurements that may be desired in during intensification.

In the most general sense, a mechanical sealing mechanism that is installed multiple times performs the function of creating a "hydraulic seal", where a hydraulic seal is understood as sufficient flow restriction or blockage, due to which the fluid is forcibly directed to a location other than the location to which it would flow if there was no current limit specified. More specifically, this broad definition of "hydraulic seal" includes the concept of "Perfect Hydraulic Seal" in which all flow is directed to a location different from the location it would be directed to if the specified flow restriction were not present, and includes the concept of "non-ideal hydraulic sealing" in which a significant portion of the flow is directed to a location different from the location to which it would be directed were it not for the 7/0 specified flow limitation. Although it is generally desirable to use a mechanical seal that is repeatedly set to provide a perfect hydraulic seal to achieve optimum excitation, a sealing mechanism that produces a less than perfect hydraulic seal can be used and economically advantageous processing can be provided, even if there is no ideal deviation in intensification processing.

In the first preferred embodiment of the invention, coiled tubing is used as a means of deployment, and the new method involves sequentially perforating and then exciting individual zones from the bottom up of the completion interval, while the intensification fluid is pumped down into the annular space between the production casing and the coiled tubing. As discussed in more detail below, this variant of the new device and method provides significant advantages over existing intensification technologies that use coiled tubing and component tubing, and this variant can be used in a wide range of wellbore architectures and intensification treatments.

More specifically, the first preferred embodiment of the new method and device uses a deployment system, signal receiving means, slaughtering equipment and operations, which are described in more detail below, and the various components, their orientation and steps of operations are selected only for explanation in such a way that they are Correspond to components and operations that can be used to perform hydraulic wedging of cracks in multiple intervals. and)

In the first preferred option, the device for hydraulic wedging excitation of cracks includes downhole equipment, which is deployed in the wellbore with the help of coiled pipes. The slaughter equipment includes a device for perforating, a mechanical sealing mechanism that can be installed many times; locator of coupling joints of the casing column, circulation channels and other auxiliary components (as described in more detail below). -

Moreover, in this first preferred embodiment, the perforating device comprises a system of firing perforators with selective ignition of charges (in which cumulative charges are used for perforating), a mechanical seal mechanism that can be set multiple times, containing an inflatable packer that can be set multiple times, a multi-position mechanical wedge gripper to prevent, when installed, downward axial movement of the drilling equipment, and pressure equalization channels located above and below the multi-position inflatable packer.

In addition, in this first preferred embodiment, the conductive communication line can be installed inside the coiled tubes and used to transmit signals intended to actuate the charges, which are selectively ignited for perforating, and to transmit electrical signals for the coupling joint locator casing pt) with the column, using the depth measurement of the downhole equipment.

Figure 1 shows an example of the type of surface equipment that can be used in the first; preferred option. It includes a rig that contains a very long lubricator 2 with a coiled pipe injector head 4 suspended high in the air by a crane boom 6 connected to a crane base 8. The wellbore typically includes a surface casing section 78 located partially or completely within the cement casing 80 and a production casing 82 located partially or completely within the cement casing 84, with the inner wall of the wellbore formed by the production casing 82. The wellbore preferably passes to a depth slightly exceeding the depth of the lowest excitable interval, which is necessary for the installation of downhole equipment connected to the end of the coiled pipes 106. The pipes 106 are introduced into the wellbore using the injector head 4 and the lubricator 2. The lubricator 2 is also connected to preventers from 10, which can be remotely activated in case of operational failures. The base 8 of the crane, the boom 6 of the crane, the head 4 of the injector, the lubricator 2, the anti-fallout preventers 10 (and the auxiliary control and/or actuation components combined with them) are components of the standard equipment of the well, which allow WHAT is well known to specialists in this area, perform the processes of safe installation of downhole equipment with coiled pipes into the well under pressure, and then their extraction from the well under pressure.

F) Using readily available existing equipment, the height of the injector head 4 from ground level is about 90 feet, and the 5-shaped elbow 12 (where the spiral pipes are bent for their vertical entry down into the well) is about 105 feet from ground level. The base 8 of the crane and the boom 6 of the crane must withstand the weight of the head 4 of the injector, pipes 106, as well as any load during possible fishing operations (when releasing the well tool and equipment with the help of a jack and pulling it out of the well).

Generally speaking, the lubricator 2 should have a length that exceeds the length of the downhole equipment to allow safe deployment of the downhole equipment in the wellbore under pressure. Depending on the requirements of 65 TO full length and according to engineering calculations for a specific application, to ensure the stability of the injector head 4 and the lubricator 2, the cable ties 14 can be connected in different locations to the injector head 4 and to the lubricator 2. The cable ties 14 should be securely fixed on the ground to prevent unwanted movement of the head 4 of the injector and the lubricator 2, so that the integrity of the pressure-resistant surface components is not violated. Depending on the requirements for the full length

Alternative suspension systems for the injector head and lubricator can also be used (specialized drilling rigs with coiled pipes or well overhaul rigs).

Figure 1 also shows various wellhead components that can be used to regulate well flow and hydraulic isolation during rig assembly and disassembly operations, as well as formation intensification (excitation) operations. The crown valve 16 is used as an isolation device 7/0 Sections of the wellbore, which is above it, from the section of the wellbore, which is below the crown valve 16. The upper main valve 18 and the lower main valve 20 form a valve system for isolating the pressure of the wellbore above and below their respective locations. Depending on the specifics of the work at the site and the technology of the intensification operation, not all of the specified isolating type valves may actually be required and will be used.

Fig. 1 also shows the side outlet injection valves 22, which determine the location for pumping (injection) fluids for intensification into the wellbore. The pipes from the surface and intensification pumps are connected with the help of appropriate fittings and/or connecting flanges to the side discharge injection valves 22, with the help of which fluids for intensification are pumped into the wellbore. When installing other suitable equipment for regulating the flow, the fluid can also be diverted from the wellbore using the side discharge injection valves 22. It should be borne in mind that the inner space of the coiled pipes 106 can also be used as a channel for pumping the fluid into the wellbore.

Shown in Fig. 1, the trunks 24 of the well are used to store spare parts of downhole equipment or emergency downhole equipment 27, or to store downhole equipment that has already been used during previous operations. Downhole equipment storage wellbore shafts 24 can be shallower so that downhole equipment, which may contain i) perforating charges, can be securely held in place by surface wedge grips 26 so that perforating charges are located below ground level until the downhole equipment is pulled out and connected to the coiled tubing 106. The downhole storage wellbore 24 may contain cemented or uncemented casing or may be completely unlined. The actual number of well barrels 24 for the storage of drilling equipment, which is required for a specific operation, depends on the requirements for a complete technological operation. The trunks 24 so of the well for the storage of bottom-hole equipment should be located within the reach of the boom 6 of the crane to allow quick replacement of the bottom-hole equipment during the intensification operation without the need to physically move the base 8 of the crane to another location. uh-

Figure 2 shows coiled tubing 106 equipped with a coiled tubing coupling 110 that can be mated to a shear pin plug assembly adapter 112 that includes both a shear pin plug mechanism and a catch neck, and allows to pass fluids under pressure, and the conductive communication line 102. The adapter 112 of the plug assembly with a shear pin and a fishing neck can be "connected to an adapter with a shear pin and a fishing neck can be connected to an adapter 114, nt") with which contains a channel circulation, intended for the passage of washing waste from the space above the inflatable

And by the packer 120, which is installed many times or to pass the fluid that is pumped into the y? a well using coiled pipes 106. The adapter 114 of the circulation channel contains a valve block that controls the circulation channel 114 and the upper channel 116 of pressure equalization. Upper channel 116

The pressure equalization can be connected to the lower pipe pressure equalization channel 122 via an inflatable -I packer 120 installed multiple times. Both the circulation channel 114 and the upper equalization channel 116 are preferably open in the operating position and allow pressure equalization within the coiled pipes. and in the annular space of the casing string. In this description, the term "working position" refers to the situation in which all the components of the downhole equipment have a configuration that allows unimpeded axial 5p movement up and down the wellbore. The lower alignment channel 122, which is located below the inflatable packer 120, which is installed many times, is always open, so the flow between the alignment channels is controlled by the upper alignment channel 116. The channels of circulation and equalization can be closed at the same time when a small compressive load is applied to the downhole equipment. To prevent potential backflow into the coiled pipes, when in the operating position in the circulation Channel 114 is open, such a surface pressure must be applied to the coiled pipes 106 that the pressure inside the circulation channel 114 exceeds the pressure in the wellbore directly from the external

F) sides of channel 114 circulation. The inflatable packer 120, which is installed many times, is hydraulically isolated from the internal pressure of the coiled pipes in the working position. The inflatable packer 120, which can be installed many times, can provide pressure transfer due to internal valves controlled by the internal pressure of the coiled pipes while applying a small compressive load to the downhole equipment.

Mechanically actuated multi-axial locking devices or "wedge grippers" 124 may be installed below the multi-position inflatable packer 120 to prevent movement down the wellbore. Mechanical wedge grippers 124 can be actuated using a "continuous )" mechanism due to the cyclic change of axial load 65 between compression and extension. The connecting adapter 126 of the conductive line is located above the locator 128 of the coupling joints of the casing and the system of charges for perforating with selective ignition.

The connecting adapter 130 of the perforation system connects the locator 128 of the coupling joints of the casing column with the head 152 of charges with selective ignition. The perforation system can be designed taking into account the number, location and thickness of hydrocarbon-bearing sands within a given zone. The perforation system can

Contain one perforation block (eg 134) for each area to be treated. The first (lowest) perforation block contains the head 132 of selective ignition and the body of the perforator 134, in which charges 136 for perforation are loaded and in which the detonation system with selective ignition is mounted.

This preferred variant of the new method includes the following operations, and as a technological operation for the explanation of the invention, multi-stage hydraulic wedging fracturing is selected. 70 1. Well drilling and casing cementing Through the intervals to be completed, as well as, if desired, drilling and completion of one or more wellbores for storage of downhole equipment. 2. Identification of specified zones within completion intervals (usually due to a combination of the log diagram registered in the uncased wellbore and the log diagram registered in the cased well).

C. Deployment of downhole equipment and blocks (assemblies) of shooting perforators for each downhole equipment intended to be used during the intensification operation, taking into account the number, location and thickness of hydrocarbon-bearing sands within the given zones. 4. Preparation of a drum of coiled pipes for the preferred version of the downhole equipment described above.

The drum of coiled pipes must also contain a conductive line of communication, which is used to transmit signals to actuate the firing perforators. Preferably, the desired amount of spare or emergency bottom-hole equipment is also prepared, which is stored in the well barrel(s) for the storage of bottom-hole equipment. Coiled pipes of slaughter equipment with coiled pipes. 5. As shown in Fig. 1, the coiled pipes 106 with the bottom-hole equipment are introduced into the well through the lubricator 2, and the head 4 of the injector of the coiled pipes is suspended using the boom 6 of the crane. 6. Coiled pipes and bottom-hole equipment are introduced into the well when choosing the depth of location of the bottom-hole i) equipment using the locator 128 (Fig. 2) of the sleeve connections of the casing string. 7. Coiled tubing and downhole equipment are passed below the lowest predetermined zone to ensure a wellbore depth below the lowest perforations sufficient to accommodate the downhole equipment (i.e. below the first set of perforations during fracturing operations. As shown in Fig. 2, the inflatable packer 120 , and the mechanically actuated multi-position wedge grippers 124 are in the operating position. 8. As shown in Fig. 3, the coiled tubing and downhole equipment are then raised to this position in the wellbore. , in which the first (lowest) set of charges 136 for perforating, which is contained in the first perforating unit 134 of the perforating system with selective ignition, is located directly opposite the lowest set zone, and accurate depth control can be obtained from the readings of the locator 128 of the clutch casing joints and coiled pipe depth gauge system (not shown).The action moves The upward movement of the drilling equipment to the location of the first perforated interval transfers the mechanical wedge gripper in the form of a "continuous ./)" mechanism (not shown) to the position of the previous "blocking", and the subsequent downward movement forcibly sets the mechanical wedge gripper, which in c is set many times 124 in locking position, due to which further downward movement is prevented. It should be borne in mind that the additional cyclical change of the axial load of the coiled pipes from compression;" to tension and vice versa will turn the mechanical wedge grippers, which are set many times in the working position. In this way, a mechanical wedge gripper is used in the form of a "continuous U" mechanism, due to the use of compressive and tensile loads transmitted by means of suspension -I (coiled pipes), to activate and deactivate mechanical wedge grippers. 9. The first set of charges 136 for perforating is selectively ignited due to remote activation by means of a conductive line 102 of communication, which is connected to the first head 132 of selective ignition,

Go! at the same time, perforations 230-231 are punched through the casing 82 and the cement shell 84, which establish a hydraulic connection with the formation 86. It should be borne in mind that any set of perforations can be used, for example, if desired, a set with one perforation, but usually multiple perforations provide better processing results. It should also be borne in mind that multiple segments of the perforation block can be fired when a given number of perforations is desired, for example to eliminate an actual or expected misfire or simply to increase the number of perforations. It is also necessary to keep in mind that the two interval is not necessarily a single sand collector. A plurality of sand intervals may be perforated and processed in a single processing level using other deflection agents suitable for simultaneous deployment at a given processing level in accordance with the present invention. moved to the position of the circulation channel 114, immediately below the deepest perforation 231 of the specified first predetermined zone, to minimize the potential for the wedging agent to enter above the inflatable packer 120, which is installed multiple times and to minimize the high velocity flow of the wedging agent behind the drilling equipment 11. The first level of processing for the excitation of cracks is initiated by circulating (supplying) a small volume of fluid down into the coiled pipes 106 through the circulation channel 114 (using a volumetric pump).

After that, the intensification fluid begins to be pumped down into the annular space between 65 coiled pipes 106 and the production casing string 82 at rates of crack excitation.

The flow of a small volume of fluid down into the coiled tubing 106 serves to maintain a positive pressure within the tubing 106, counteracting the backflow of the wedging media into the tubing 106 and counteracting the stress on the tubing 106 during fracturing operations.

It should be borne in mind that alternative means of counteracting the crimping of the coiled pipes can be used, and an internal valve mechanism can be used to keep the circulation channel 114 in the closed position, while the positive pressure in the coiled pipes 106 is created using a surface pump. In an example of hydraulic fracturing to intensify a 15-acre sandy lenticular body containing gaseous hydrocarbon, the first fracturing level may be formed from the following "sub-levels": (a) 5,000 gallons of water at 295 CSU; (b) 2,000 gallons of mesh structure gel, 7/0 Containing 1 lb. per gallon of wedging agent; (c) 3,000 gallons of gel mesh holding 2 pounds per gallon of wedging agent; (d) 5,000 gallons of mesh structure gel containing 3 pounds per gallon of wedging agent; and (e) 3,000 gallons of gel mesh holding 4 pounds per gallon of wedging agent so that 35,000 pounds of wedging agent are injected into the first zone. 12. As shown in Fig. 4, all sub-levels of the first hydraulic fracturing operation are completed 7/5 by the creation of the first wedging crack 232. 13. At the end of the first level of intensification, the wedging agent in the wellbore prevents the immediate movement of coiled pipes and downhole equipment; the fluid medium can circulate through the circulation channel 114 to wash and clean the wedging agent, which is necessary to release the coiled pipes and downhole equipment to ensure the movement. 14. As shown in Figure 5, the coiled tubing and drilling equipment are then pulled up the wellbore to a position just above the second-from-bottom depth of the predetermined zone, so that the second set of perforating charges 146 contained in the system 144 perforating with selective ignition, is located slightly above the second from the bottom in the depth of the given zone, and again accurate control of the depth is obtained from the readings of the locator of the coupling joints of the casing string 128 and the depth gauge systems of the coiled steel pipes. The action of moving the downhole equipment up the wellbore (to a position slightly above the second interval to be perforated) transfers the mechanical wedge gripper in the form of a "continuous //" i) mechanism to the pre-blocking position. An additional cyclic change of loads from compression to tension will return the mechanical wedge gripper in the form of a "continuous /" mechanism to the working position. Coiled pipes and drilling equipment are then lowered down the wellbore to the position of the charges 146 for perforating, which are contained in the perforating system 144 with selective ignition, located directly opposite the second from the bottom in the depth of the given zone, and again precise control (87 depths are obtained from the readings of the locator 15. The second set of charges 146 for perforating is selectively ignited due to remote activation by means of the second head 142 of selective ignition, which allows to pierce the casing 82 and the cement shell 84 and establish hydraulic communication with the formation 86 through the resulting perforations 240, 241. 16. As shown in Fig.b, the coiled tubing may be moved down the wellbore to install the downhole equipment several feet below the deepest perforation 241 of the second predetermined zone.

Further movement of the downhole equipment up the wellbore to install the channel 114 « 470 Circulations directly below the deepest perforation 241 of the indicated second predetermined zone, will transfer stv) s mechanical wedge grabs, which are repeatedly installed 124 in the pre-blocking position, and further downward movement will be forcibly install mechanical wedge grips, which many times;" are set 124 in the blocking position, due to which further downward movement is prevented. 17. As shown in Fig. 7, the movement down engages the mechanical wedge grippers, which many times

124 are installed with the wall of the casing column 82, due to which further downward movement of the bottom-hole equipment is prevented. Then a compression load is applied to the coiled pipes, and this load closes the circulation channel 114 and the upper equalization channel 116, and due to the connection equalizes the pressure between the inflatable packer 120, which is installed many times, and the inner space of the coiled pipes.

Go! The compressive load also blocks the circulation channel 114 in a position immediately below the deepest 5o perforation 241 of the specified second predetermined zone (to minimize the potential for the wedging agent to enter above the inflatable packer 120, which is installed many times and to create a minimum flow rate of the wedging agent behind the downhole equipment ), wherein the inflatable packer 120, which is installed multiple times, is located between the first and second perforated intervals. 18. An additional compressive load is applied to the coiled tubing and downhole equipment to test the mechanical wedge grippers, which are installed 124 many times to ensure that the additional downward force does not cause additional movement of the downhole equipment down the (F, wellbore. ka 19 As shown in Figure 8, the inflatable multiple packer 120 is actuated by inflating the coiled tubing 106, thereby creating a hydraulic seal above and below the inflatable multiple packer 120. The compressive load continues to be applied to downhole equipment to maintain pressure equalization between the inner space of the coiled pipes and the multi-set inflatable packer 120 to keep the circulation channel 114 and the upper leveling channel 116 closed, as well as to keep the multi-set mechanical wedge grippers 124 in the excited position and locking Inflatable packer 1 20, the reusable packer is kept in service 65 by maintaining pressure in the coiled tubing 106 by means of a surface pumping system (it should be noted that the reusable inflatable packer may also be kept in service by the locking pressure in its elements, with the use of an internal valve remotely controlled from the surface using a means of generating signals compatible with other components of the downhole equipment and other existing means of generating signals). 20. The second level of fracture excitation processing is initiated by pumping fluid down into the annular space between the coiled tubing 106 and production casing 82 at fracture excitation velocities while maintaining a compressive load applied to the downhole equipment to keep the circulation channel 114 closed and the upper alignment channel 116, the pressure of the coiled tubes being maintained at a level sufficient to prevent kinking of the tubes and to maintain the inflatable packer 120, which is installed multiple times, in an inflated state when it serves as a hydraulic seal between the annular pressure above the packer, to during and after hydraulic fracturing, and by the pressure of the compacted wellbore below the inflatable packer, which is installed many times. 21. All sub-levels of hydraulic fracturing are pumped and leave only the minimum bottom passage of the last sub-level loaded with wedging agent in the wellbore, so as not to displace 7/5 excess hydraulic fracturing. If in the course of this processing the seal of the inflatable packer 120, which is set many times, is disturbed, then the processing level can be temporarily stopped to check the quality of the seal of the packer above the highest (smallest) existing perforations (for example, perforations 240 on

Fig. 8), after installing the inflatable packer 120, which is installed many times, in a pipe without side holes.

If it is necessary to conduct a test of the integrity of the seal, it is preferable to conduct such a test

Carry out a circulation and flushing operation to remove from the wellbore any wedging agent that may be present in the wellbore. This circulation and flushing operation can be performed by opening the circulation channel 114 and then pumping the fluid for circulation down into the coiled pipes 106 to remove the wedging agent from the wellbore. 22. As shown in Fig. 9, all sub-levels of the second crack excitation operation / end with the creation of the second propagating crack 242. 23. After the second crack excitation operation is completed and the pumping of the fluid medium is stopped for i) intensification down into the annular space formed between coiled pipes 106 and production casing 82, a small tensile load is applied to the pipes 106 while maintaining the internal pressure of these pipes 106. The applied small tension primarily isolates the pressure of the inflatable packer 120, which is set many times from the pressure of the pipes 106, due to which the pressure is fixed in the inflatable multiple packer 120 and thereby maintain an overpressured seal and provide substantial resistance to axial movement of the inflatable multiple packer 120. The applied stretch can then open the circulation channel 114 and the alignment channel 116 , due to which the pressure of the coiled pipes is 106 can be vented into the annular space formed by the pipes 106 and production casing 82, which simultaneously allows the pressure above and below the inflatable packer 120, which is installed many times, to equilibrate. The surface pumping system, which creates the internal pressure of the pipes 106, can be turned off after equalizing the pressure in the well. 24. After the pressures inside the coiled tubing 106, in the annular space formed by the tubing 106 and the production casing string 82, above the inflatable packer 120, which is installed multiple times, and in the "Annular space formed by the drilling equipment and the production casing string 82, below with an inflatable packer 120, which is installed many times balanced, applied to the pipes 106 compressive. the load closes the circulation channel 114 and the upper equalization channel 116, before the transfer of internal pressure from packer 120 into tubing 106. This release of internal pressure from packer 120 allows packer 120 to be moved away from the production casing wall, as shown in Figure 10, in the absence of an external pressure drop applied to packer 120 that would create forces and displacements, which can damage coiled -I pipes 106 or drilling equipment. 25. Immediately after returning to the initial position of the inflatable packer 120, which is installed repeatedly, as shown in Fig. 10, the tension applied to the coiled pipes and downhole equipment can turn off

Go! multi-position mechanical wedge grips 124 that allow the downhole equipment to move freely so that the downhole equipment can be installed higher in the wellbore. - 26. If at the end of the second level of intensification, the wedging agent remaining in the wellbore c does not allow immediate movement of the coiled pipes and downhole equipment, then the fluid can be circulated through the circulation channel 114 for washing and cleaning from the wedging agent, so that release the coiled pipes and downhole equipment and allow the downhole equipment to move up after releasing the multi-set inflatable packer. 27. The process described above is repeated until individual excitation of all zones is carried out

Ф) are planned (Fig. 5-10 shows the slaughter equipment designed for excitation of three zones). ka 28. After the completion of the intensification process, the downhole equipment is returned to the working position and the block of coiled pipes and the downhole equipment are pulled out of the wellbore. 60 29. Once all the desired target zones have been excited, extraction from the well can be started immediately. 30. If it is desirable to excite additional zones, the drum of coiled pipes can be combined with slightly modified downhole equipment, as shown in Fig. 11. In this system, the only change to the preferred downhole equipment described above is the addition of a selective ignition kit mechanical plug 164 or selective ignition kit packer plug 164 installed below the lowest selective ignition perforation block 65, as shown in Fig. 11. Typically, a packer plug or crack partition can be used as the mechanical plug 164 of the selective ignition kit. A crack partition is usually preferable if one wants to simultaneously separate the resulting zones with a plug immediately after the intensification operation. 31. The modified slaughter equipment shown in Fig. 11 includes a perforating system with selective ignition (Fig. 11 shows a perforating system that includes firing perforators 174, 184, 194, combined with charges 176, 186, 196, and with heads 172 . selective ignition, which is installed using the selective ignition head 162. The modified 7/0 downhole equipment is introduced into the well using a lubricator and a coiled pipe injector head suspended by a crane or a derrick above the wellhead. 32. Coiled pipes and downhole equipment are introduced into the well, choosing the depth with the help of a coupling joint locator. 33. As shown in Fig. 11, coiled tubing and modified bottoming equipment are inserted into the wellbore /5 in such a way as to install the selective ignition mechanical plug 164 in a position over the last previously excited zone 252. 34. As shown in Fig. 12, the selective ignition head 162 is ignited to install the selective ignition mechanical plug 164 in a position above the last previously excited zone 252. 35. After activating the selective ignition head 162, the packer-plug is set to install the selective ignition packer-plug 184, the pipes and modified downhole equipment are wound then raised to a location in the wellbore where the first (lowest) set of perforating charges 176 contained in the selective ignition perforating system is directly opposite the next lowest predetermined zone to be perforated, and accurate depth control can be obtained from the locator readings 128 casing couplings columns and coiled pipe depth gauge systems, as provided for in the surface equipment. The action of moving the downhole equipment upward to the location of the first perforated interval moves the mechanical wedge grippers into the locking position, and i) an additional cyclic change of the axial load of the coiled pipes from compression to tension and vice versa will return the mechanical wedge grippers, which are set many times, to the working position. 36. As shown in Fig. 12, the first set of charges 176 for perforating in the modified ordnance soz equipment is selectively ignited due to remote actuation with the help of the second head 172 of selective ignition, while piercing the casing 82 and the cement shell 84 and obtaining -- perforations 270, 271, through which a hydraulic connection is established with the formation 86. so 37. If there is an insufficient gap between the previously performed perforations 250, 251 and the location of the next set of perforations 270, 271, which does not allow proper installation of the downhole equipment for "perforating , isolation and intensification of the next set of perforations 270, then the packer plug 164 of the selective ignition can be installed below the last previously excited perforations 250, 251, and the inflatable packer 120, which is installed many times, can be used during the first operation of intensification for isolation of the uppermost perforations 270, 271 from previously excited perforations 250, 251. 38. The process described above is repeated until the individual excitation of all the planned zones is carried out (Fig. 11-12 shows the slaughter equipment designed for the excitation of three additional zones). z c Those skilled in the art will readily appreciate that the preferred method of suspension when using a wedging agent fluid medium is conventional component tubing or coiled tubing, preferably with one or more;" circulation channels that make it easy to remove the remaining wedging agent from the wellbore.

However, for treatments such as acid fracturing or acid treatment of the parent rock, such

The capability may not be required, and they can easily be accomplished with a deployment system using a cable, such as a wire rope or wireline, or using a downhole tractor system. Specialists will easily understand that, depending on the tasks of a specific technological operation, there may be

Go! various pumping systems are used, including: (a) pumping down into the annular space formed between the cable or tubing (if the deployment method uses cable or tubing) and the casing wall; - (b) pumping down into the inner space of coiled pipes or component pipes, if the suspension method c provides for the use of coiled pipes or component pipes, and excessive friction and erosion due to the wedging agent do not create problems for the well of the depth under consideration; (c) simultaneous pumping down into the annular space formed between the tubing (if tubing is used in the deployment method) and the casing wall, and into the interior of the tubing, if excessive friction and erosion due to the wedging agent do not pose a problem for the well of the depth under consideration .

F) Fig. 13 shows the second variant of the invention, in which coiled pipes are used as a means of deployment, and excessive friction and the use of a wedging agent do not cause concern, or the wedging agent is not pumped during the technological operation. Fig. 13 shows that the coiled pipes 106 are used to suspend the downhole equipment and its components. In this variant, processing of individual zones is carried out in sequence from the smallest locations in the wellbore to the deepest locations in the wellbore. In the variant shown in Fig. 13, the circulation channel 114 is located below the packer 120, so that the fluid medium for processing the formation can be pumped down into the inner space of the coiled pipes 106, and then can exit through the circulation channel 114 and be pumped to enter the predetermined 65 perforations . As an example of operation, Fig. 13 shows that the packer 120 can be activated and installed below the perforations 241, which are combined with the previous zone of hydraulic fracturing 242 of the reservoir.

The inflatable packer 120, which is installed many times, provides such hydraulic isolation that when the formation fluid is subsequently pumped down into the coiled pipes 106, the treatment fluid is forced to enter the previously made perforations 230, 231 and creates new hydraulic

Blasting 232. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals.

Figure 14 shows a third embodiment of the invention, in which coiled pipes are used as a means of deployment, and excessive friction and the use of a wedging agent do not cause concern, or the wedging agent is not pumped during the technological operation. Fig. 14 shows that coiled pipes 106 7/0 are used for suspension of downhole equipment and its components. In this version, processing of individual zones can be carried out in any order. In this variant, as shown in Fig. 14, an inflatable sealing mechanism is used, with a double-sided packing packer 125 as a multiple installation sealing mechanism, and the circulation channel 114 is now located between the upper inflatable sealing element 121 and the lower inflatable sealing element 123. After actuation of the upper inflatable /5 sealing element 121 and the lower inflatable sealing element 123, the formation fluid can be pumped down into the inner space of the coiled pipes 106, and then can exit through the circulation channel 114 and be pumped to enter the predetermined perforations. As an example of operation, Fig.14 shows that the upper inflatable sealing element 121 and the lower inflatable sealing element 123 are actuated and installed opposite the perforations 241, which are connected to the next zone to be broken. The inflatable packer 20, 120, which is installed multiple times, provides such hydraulic isolation that when the formation fluid is subsequently pumped down into the coiled tubing 106, the treatment fluid is forced to enter the previously made perforations 240, 241 and creates new hydraulic breaks 242. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals.

Fig. 15 shows the fourth embodiment of the invention, in which the communication line 102 is used as a means of deployment for the suspension of the slaughter equipment and its components. In this variant, individual zones are treated in sequence from the deepest locations in the wellbore to the shallowest (8) locations in the wellbore. In this variant, as shown in Fig.15, the fluid medium for processing the formation can be pumped down into the annular space between the communication lead line 102 and the wall of the production casing string 82, and then can be forced to enter the predetermined perforations. In this embodiment, the multi-installable inflatable packer 120 also includes an internal electrical pumping system 117 powered by electrical energy transmitted to the wellbore via a wireline -- which allows the inflatable packer to be inflated or deflated (pumped out). 120, which is installed many times, using the wellbore fluid. Figure 15 shows that the packer 120 can be activated and installed below the perforations 241, which are connected to the next zone of hydraulic fracturing. The packer 120 provides such hydraulic isolation that during further pumping of the fluid for processing the formation down into the annular space between the conductive line 102 of the communication and the production casing string 82, the fluid for processing is forced to enter the perforations 240, 241 and creates new hydraulic fracturing 242. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals. "

The fifth variant of the invention provides for the deployment of an additional column of pump-compressor pipes in c or cables, hereinafter referred to as "component hoses", inside and/or outside the coiled pipes (or component pipes). As shown in Figs. 16 and 17, the pipe assembly hose 104 is located inside the coiled pipes 106. In this embodiment, the tubular assembly hose 104 is coupled to the multiple sealing mechanism 120, and in this embodiment, the multiple sealing mechanism 120 can be actuated by hydraulic pressure transmitted through the assembly hose 104. Generally speaking , -And a plurality of component hoses can be deployed inside the coiled pipes and/or in the annular space between the coiled pipes and the operational casing. Generally speaking, composite hoses can be used to perform a number of different operations, including (but not limited to) creating (a)

Go! hydraulic coupling to actuate individual components of the downhole equipment, including (but not limited to) the sealing mechanism and/or the perforating device; (b) pipelines for - pumping into the well or for circulation of additional fluid; (c) to collect data from c well measuring devices. It should be borne in mind that, as shown in Fig. 1b6, the downhole equipment also includes centralizers 201, 203, 205, which are used to keep the downhole equipment centered in the wellbore when its components are in the working position. 5B The use of composite hose(s) may allow hydraulic engagement and/or disengagement of a mechanical sealing mechanism, which is set many times, regardless of the value (Ф, of the hydraulic pressure inside the coiled pipes. This then allows to expand the method for the use of ka mechanical sealing mechanisms, which are many times installed requiring independent hydraulic actuation for operations. Perforating devices that require hydraulic pressure for selective ignition can be actuated by a composite hose. This can then allow the use of a lead line of communication , if it is deployed with coiled tubing and downhole equipment, as a channel or channels for the transmission of electrical signals, which may be desirable to collect data from measuring devices installed in the downhole equipment; or to actuate other components of the downhole equipment, for example, electric downhole occasion of engines that can generate 65 revolutions or torque for the components of the slaughter equipment. Alternatively, the stock hose can be used to power a hydraulic motor, or torque for downhole equipment components. Alternatively, the assembly hose may be used to power a hydraulic motor designed to actuate various downhole components (eg, a hydraulic motor to turn on and off a seal mechanism that is installed multiple times).

The use of composite hose(s) can allow any fluid to be pumped into the well or circulated to multiple locations as desired for precise control. For example, to reduce wedging agent deposition on the packing mechanism during hydraulic fracturing, a component hose(s) may be used that allows for continuous or intermittent flushing and circulation to prevent the accumulation of 7/0 Wedging Agent on the packing mechanism. For example, one component hose may pass directly above the mechanical seal mechanism that is installed multiple times, while another component hose may pass directly below the mechanical seal mechanism that is installed multiple times. Then, if desired, a fluid medium (e.g., nitrogen) may be injected into the well for circulation at each or both locations to flush the wedging agent from the area surrounding the sealing mechanism, reducing the potential hazard of jamming of the drilling equipment due to wedging buildup. agent In the case of fluid circulation, it is necessary to select the size of the component hose and the type of fluid to ensure the desired speed so that the flow of the fluid is not inhibited by the frictional pressure in the component hose.

In addition to the component hoses formed by the tubing string that provide hydraulic communication in the wellbore as a means of transmitting signals to actuate downhole equipment components (or as a possible means of transmitting signals to register data from downhole sensors at the surface), one or more conductive communication lines or one or more fiber-optic cables can be deployed in the wellbore to create electrical or electro-optical communication in the wellbore as a means of transmitting signals to actuate the components of the bottomhole. Figure 18 shows the sixth This is an embodiment of the invention, in which the tractor system, which includes the upper tractor assembly 131 of the drive and the lower tractor assembly of the drive 133, is connected to the downhole equipment and is used to deploy and i) select the position of this equipment in the wellbore. In this variant, processing of individual zones is carried out in sequence from the deepest locations in the wellbore to the smallest locations in the wellbore. In this variant, the downhole equipment also contains an internal electric pumping system 117, which is provided with electrical energy transmitted to the well via a conductive communication line 102, which allows to inflate or deflate (pump out) the inflatable packer 120, which is installed many times , using the wellbore fluid. In this variant, the fluid medium for processing the formation is pumped down into the annular space between the conductive communication line 102 and the wall of the production casing string 82, and is forced into the predetermined perforations. Figure 18 shows that the inflatable packer 120, which is installed many times, can be activated and installed below the perforations 241, which are connected to the next fracturing zone. The inflatable packer 120, which is installed multiple times, provides such hydraulic isolation that when the formation fluid is then pumped down into the annular space between the communication line 102 and the production casing 82, the treatment fluid is forced into the perforations 240, 241 and creates new hydraulic fractures « 242. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals. z с As an alternative to this sixth option, the tractor system may be self-propelled, controlled by on-board computer systems, and it may include on-board signal processing systems, so that ;" there is no need to use cables or pipes to select the position, to control and/or actuate the tractor system. Moreover, the control of various components of the downhole equipment can also be carried out with the help of on-board computer systems, and these components can contain on-board signal processing systems, so that there is no need to use cables or pipes to control and/or actuate these components. For example, signal processing systems, so that there is no need to use cables or pipes to control and/or actuate the specified components. Example,

Go! the tractor system and/or downhole equipment components may have on-board power sources (eg, batteries), computer systems, and data transmission and reception systems so that the tractor and downhole equipment components can be controlled remotely from the surface using remote processing systems s signals, or, alternatively, various on-board computer systems can be pre-programmed on the surface to perform the desired sequence of operations when deployed in the wellbore.

According to the seventh variant of this invention, jets of abrasive (or erosive) fluid medium are used as means for perforating the wellbore. Jet injection of an abrasive (or erosive) fluid is a common method widely used in oil production for cutting and perforating well strings, pump-compressor pipes or other components of the wellbore and wellhead. The use of coiled pipes or composite pipes as a means suspensions of the downhole equipment creates a pipeline for the deployment of the abrasive fluid jet cutting system. For this, the downhole equipment includes a jet tool. The jet tool allows the injection of an abrasive (or erosive) fluid or suspension into the well under high pressure and at high speed, through pipes and through nozzles. The abrasive (or erosive) fluid cuts through the production casing wall, the cement casing, and penetrates the formation, providing a path for the fluids to communicate with the formation. A random distribution of holes and 65 Fissures can be obtained from the use of pits of the jet tool throughout the termination interval during the intensification operation. Typically, abrasive (or erosive) fluid cutting and perforating can be easily performed under a wide range of pumping conditions, using a wide variety of fluids (water, gel, oil, and liquid-gas combinations) and using a wide variety of solid materials (sand, ceramic materials, etc.), if the use of abrasive hard materials is required for specific wellbore perforation, the jet tool is approximately one to four feet long, then the height requirements of the surface lubrication system (lubricator system) are significantly reduced (which can have a height of up to 60 feet or more) compared to the height requirements of using conventional selective ignition perforating units as the perforating device. Lowering the height requirements of the surface lubrication system provides multiple benefits, including lower cost and reduced 7/0 operating time.

Figure 19 shows in more detail the seventh embodiment of the invention, in which the jet tool 310 is used as a device for perforating, and the component pipes 302 are used to suspend the downhole equipment in the wellbore. In this embodiment, a mechanical, compression-set, multiple-set packer 316 is used as a multiple-set sealing device; the mechanical locator 318 of the coupling joints of the casing string is used to control the depth of the downhole equipment and to select its position; the adapter of the unidirectional shut-off valve with full opening of the hinged type 304 is used to prevent the flow of the fluid up the component pipes 302; the adapter 306 of the plug assembly with a shear pin and a catch neck is used as a safety release device; the adapter 308 of the circulation channel and the equalization channel 2o is used to ensure the circulation of the fluid medium and to equalize the pressure above and below the mechanical one, which is established due to compression, which is established many times, of the packer 316 under some circumstances; the adapter 314 of the one-way shut-off ball valve is used so that the fluid can flow up from the space below the mechanical, installed due to compression, the packer 316, which is installed many times only through the adapter 308 of the circulation channel and the equalization channel.

The jet tool 310 includes jet channels 312, which are used to accelerate and direct i) abrasive fluid pumped down into the components of the pipe 302, so that the production casing string 82 is subjected to a direct impact of the jet. In this configuration, the mechanical locator 318 of the coupling joints of the casing is connected in an appropriate manner with the mechanical one, subjected to a direct impact of the jet. In this configuration, the casing string coupling mechanical locator 318 is mated in a suitable manner with the compression set mechanical packer 316, which is set multiple times in such a way as to - allow fluid to flow upward from the space below the mechanical, compression, which is set at the expense of the packer 316, which is set many times, to the adapter 308 of the circulation channel and the alignment channel. The cross-sectional area of the pipelines of the hydraulic system, which are inside the adapter 308 of the circulation channel and the equalization channel, is selected in such a way that it exceeds the cross-section of the jet channels 312, so that a large part of the flow inside the component pipes 302 or the downhole equipment mainly flows through the adapter 308 the circulation channel and the equalization channel, and not through the jet channels 312, when the adapter 308 of the circulation channel and the equalization channel is in the open position.

The adapter 308 of the circulation channel and the equalization channel is opened and closed by moving "

Up and down component pipe 302. with c In this variant, component pipes 302 are preferably used together with a mechanical packer 316 installed by compression, which is installed many times, because a mechanical one installed by ;" due to compression, the multi-set packer 316 can be easily activated and deactivated (deactivated) by vertical movement and/or rotation applied through the component tubes 302. Vertical movement and/or rotation is applied through the component tubes 302 by a block for -I feeding pipes into a well with high pressure at the mouth, provided in a small mobile installation for the completion of a drilled well, using a power swivel block, which is used as a surface means for connection, installation in the wellbore and removal from the wellbore

Go! component pipes 302. It should be borne in mind that the surface equipment, methods and procedures associated with the use of a block for feeding pipes into a well with high pressure at the mouth, provided in a small - mobile installation for the completion of a drilled well and with the use of a power swivel block , are common and well known to specialists in the field of connection, installation in the wellbore under pressure and removal from the wellbore with a dismantling head instead of a block for feeding pipes into a well with high pressure at the mouth, also allows connection, installation in wellbore under pressure and removal of component pipes from the wellbore under pressure; it is also common and well known to those skilled in the art of connection, installation in a pressure wellbore, and removal from a pressure wellbore

F) component pipes. It should also be borne in mind that the surface equipment includes the relevant ka manifolds, pipes and valves that allow flow between all the relevant surface components and technical means and the wellbore, including (but not limited to) through the component bo pipes, annular space between the composition pipes and the production casing, through the pumps, fluid reservoirs and return wells.

Since the compression set mechanical multiple packer is actuated by vertical movement and/or rotation of the component tubes 302, fluid can be pumped down into the component tubes 302 without the use of additional control valves 65 and/or or isolation valves that might be required when using an inflatable packer as a multiple-installation sealing device. In this case, the internal space of the component pipes 302 is used to form an independent conduit between the surface and the jet tool 310, through which the abrasive fluid can be pumped down through the component pipes 302 to the jet tool 310.

The jet channels 312 provided on the jet tool 310 create a jet of abrasive fluid

A high-velocity medium is directed to perforate production casing 82 and cement casing 84 to establish hydraulic communication with formation 86 .

Fig. 19 shows the jet tool 310, which is used to create perforations 320, leading to the first interval of the formation intended for processing, which is excited with the help of hydraulic breaks 322. Fig. 19 also shows the jet tool 310, which was reinstalled in the barrel /o the wellbore and which is used to create perforations 324 in the second interval of the formation being processed, and the mechanical packer installed due to compression, which is installed multiple times 316 can the second interval of the formation being processed, and the mechanical packer installed due to compression, which is installed is installed multiple times 316 can be actuated to provide a hydraulic seal in the wellbore prior to the use of perforations 324 in the second level 7/5 of multi-stage hydraulic fracturing.

It should be noted that the jet channels 312 can be spaced approximately six inches to one foot from the mechanical installed by compressing the multiple installed packer 316 so that after conducting the second wedging level of fracturing, on top of the mechanical of the packer 316, which is set at the expense, the compression, which is set many times, can 2o build up the tension-forming wedging agent; in this case, a non-abrasive and non-erosive fluid can be pumped down into the pipe components 302 and can pass through the jet channels 312 and/or through the circulation channel and alignment channel adapter 308 to remove the wedging agent from above the mechanical packer 316 installed by compression , which is set many times.

Furthermore, the jet tool 310 can be rotated (when the mechanical packer 316, mounted multiple times, is not actuated due to compression) using component tubes 302, which can be rotated with the help of a surface power swivel, to i) further assist in the removal of wedging agent from the top of the compression set mechanical packer 316, set multiple times. Since the perforations are created using a jet of fluid, burrs of the perforations are not formed. Since there are no perforation burrs, which are potentially a source of additional wear to the elastomers of the mechanical compression set packer 316, the durability of the mechanical compression set packer 316 can be increased compared to those with types of application in which burrs of perforations may exist.

It should also be borne in mind that the flow regulation is provided by means of the adapter 314 "from the 5 one-way shut-off ball valve, and the transition 304 of the one-way shut-off valve with a full opening of the hinged type is used only to equalize the pressure above and below the mechanical pressure established by compression of the packer Multi-set packer 316 when the pressure is below the mechanical compression set pressure of the multi-set packer 316 exceeds the pressure above the mechanical compression set multi-set packer 316. " 470 In those cases when the pressure is higher than the mechanical pressure, which is set due to compression, the packer 316, which is set many times in s, exceeds the pressure below the mechanical pressure, which is established due to compression, the packer 316, which is set many times, then the pressure is higher for mechanical, which is established at the expense of ;" compression, the multiple packer 316 can easily be reduced by conducting a controlled backflow in the newly excited zone, using the annular space between the assembly pipes 302 and the production casing 82, or by circulating a fluid with more And low density (e.g., nitrogen) down through the constituent pipes 302 and up into the annular space between the constituent pipes 302 and the production casing 82. o Use of a swing-type full-opening one-way shut-off valve adapter 304 o is preferred because its design allows pumping without restriction (free pumping) of the abrasive (or erosive) fluid into the well, and also allows the passage of control balls, which, depending on the specific details of the individual components of the downhole equipment, may fall from the surface into the flow of the fluid for control or into the hydraulic system individual components of slaughter equipment, or ensure the safe release of this equipment. Depending on the specific design of the tool, different configurations can be used to provide the functionality of the flow control valves (fountain valves) described in this option.

As an alternative to the specified seventh option, an adapter containing a fitting can be used

Ф) (nipple), which allows suspension or retention of other measuring devices or components of the slaughter equipment. This fitting, for example, can contain a conventional casing joint locator and a gamma ray tool that is deployed via a wireline and installed in the fitting, and which can be used to further diagnose the position of the downhole equipment and location. formation intervals that are of interest. Additionally, various abrasive jet tools can be deployed as part of the downhole equipment to control perforation cutting characteristics such as hole (slot) size and cutting speed, allowing for the use of different abrasive materials and/or providing system redundancy in the event of premature component 65 failure.

Those skilled in the art will readily appreciate that a variety of different components can be used in slaughter equipment.

Downhole equipment may be configured to include means for measuring reservoir, fluid, and wellbore parameters deemed desirable for the application. For example, temperature and pressure sensors can be used to measure the temperature and pressure of the well fluid during processing; the densimeter can be used to measure the effective density of the well fluid (which is especially useful for determining the distribution in the well and locating the wedging agent during hydraulic fracturing); and a radioactive detection system (eg, gamma-ray or neutron measurement systems) can be used to localize hydrocarbon-bearing zones or to identify or localize radioactive material in a wellbore or formation.

Depending on the presence of specific components of the downhole equipment and whether the perforating device creates perforation holes with burrs that can damage the sealing mechanism, the downhole equipment may have a deburring tool that allows you to scrape and remove the perforation burrs from the casing wall.

Depending on the presence of specific downhole equipment components and whether the downhole equipment components may experience excessive wear if they move in contact with the casing wall, downhole equipment may use centralizer adapters to mechanically select the downhole equipment position and eliminate or reduce the hazard its damage when moving in contact with the casing wall.

Depending on the presence of specific components of the kill equipment and whether the perforating charges can create strong shock waves and cause harmful vibrations when ignited, the kill equipment may contain vibration and shock damping adapters that eliminate or minimize the harmful effect on system parameters due to the detonation of the charge for perforating.

Depending on the deployment system used and on the tasks of a specific technological operation, perforating devices and any other desired components of the downhole equipment can be installed above or below the sealing mechanism, which is installed many times, and in the desired order relative to each other. The i) deployment system itself, whether in the form of a communication line, power line, coiled tubing, conventional component tubing, or downhole tractor, may be used to transmit signals to actuate a compaction mechanism and/or a device for perforation It is also possible to carry out the suspension of such means of signal transmission inside ordinary composite pipes or coiled pipes, which use sealing devices and perforation devices for suspension. Alternatively, the signal transmission means, whether electrical, hydraulic, or other means, may pass through a channel located outside the suspension means, or even located in one or more individual turns of coiled tubing or conventional component tubing. "

In the case of the use of fluids having a high viscosity in wells with a depth of approximately more than 8,000 feet, a number of significant technological and economic advantages can be obtained due to the application of this invention. The reduction in frictional pressure allows hydraulic fracturing in deeper wells and reduces the requirements for special fluid compositions for hydraulic fracturing. The reduction or elimination of frictional pressure occurs because a fluid with a high viscosity can be pumped " 70 Down into the annular space between the coiled pipes or other means of suspension and the operational casing 7-3) with the column. Because there is a reduction in frictional pressure compared to fluid pumping systems. high-viscosity medium down into the inner space of the coiled pipes, then the depths increase significantly. wells in which such technology can be used. For example, when deploying 1-1/2" coiled tubing in a 17 psi casing with a 5-1/2" O.D., the effective flow cross-section is roughly equivalent to a 5" O.D. casing. At the indicated effective flow cross-sections, fracturing can be performed in wells up to 20,000 feet deep and deeper, and higher injection rates (eg, approximately 10 to 30 barrels o per minute or more) can be achieved to efficiently transport the proppant and to hydraulic fracturing of the reservoir using fluids with high viscosity.

Since the annulus can usually have a larger equivalent flow cross-sectional area, a conventional fracturing fluid can be used instead of a special low-viscosity fluid (such as UBosKmei-Zspischtbregdegs SiegEgas tm fluid, which is used to reduce Frictional pressure drop Through coiled pipes Using conventional fracturing fluid technology allows formations to be processed at temperatures above 250 °C, above which expensive special fluids available at this time may begin to degrade.

The following can be used as a sealing mechanism: an inflatable device; mechanical, which is installed due to i) compression, packer, which is installed many times; mechanical, which is installed due to the compression of the packer, covering from two sides; plug-type sealing devices, and any other alternative devices which can be deployed by means of suspension and provide a hydraulic bo Sealing that can be installed multiple times, or perform an equivalent function. Both inflatable and compression-set devices exist that provide such a radial clearance between the packing elements and the casing wall (eg, approximately 0.25 to 1 inch for inflatable devices and 0.1 to 0.2 inches for compression-set devices compression) that the wear of sealing elements is significantly reduced or completely eliminated. According to the preferred embodiment of the present invention, there is a sufficient gap between the sealing mechanism in its non-operating state and the casing wall, which allows for rapid movement of input into the wellbore and output from it, without significant damage to the sealing mechanism or without pressure control, associated with pressure pulsations or well swabbing due to tool movement. The increased gap between the sealing surface and the casing wall (when the sealing mechanism is not actuated) also allows the introduction of coiled pipes and downhole equipment into and out of the well at significantly higher speeds than is possible when using systems with coiled pipes, which is at this time. In addition, in order to minimize the possibility of unwanted wear, according to the preferred option, the perforating device allows such perforation of the casing wall, in which a relatively smooth edge of the perforation hole is obtained.

Alternatively, a mechanical sealing mechanism that is installed many times may not always create a perfect hydraulic seal and may, for example, leave a small gap around the perimeter of the device. The size of such a small gap can be chosen to create a sealing mechanism (if desired) when the wedging agent closes the gap, and to eliminate the seal (if desired) by circulating fluid. Moreover, depending on the specific type of application, it is possible to carry out economically profitable work on the intensification of the reservoir, even if the ideal hydraulic /5 Sealing using a mechanical sealing mechanism, which is installed many times, is not obtained.

Since the punching device is deployed at the same time as the sealing mechanism, which is set multiple times, the depth control of all components can be carried out at the same time (simultaneously), using the same measurement standard. This eliminates the problems of depth control, which are inherent in the existing methods, when the operations of perforation and operations of intensification are carried out using two different measurement systems at different times and at different movements in the wellbore. Very accurate depth control can be achieved through the use of a casing joint locator, which is used in the preferred method of depth control.

The height of each of the individual perforated predetermined intervals according to the present invention is not limited, which contrasts with the case of previously known systems with coiled pipes and using a packer, with

Db Covering two sides in which the height of the perforated interval is limited to 15-30 feet.

Since the use of permanent packer plugs is not mandatory, an increase in the cost price and i) an increase in risks in the wellbore associated with the operations of drilling the packer plugs is excluded.

When using coiled pipes as a means of deployment, there is the possibility of using a column of coiled pipes used for the intensification operation as an operating column of pump-compressor pipes suspended in the wellhead, which leads to a significant reduction in cost by eliminating the need to mobilize (move) the drilling rig installation at the location of the well for -- installation of a conventional operating column of pump-compressor pipes, consisting of component pipes. co

Controlling the sequence of zones to be processed allows you to optimize individual levels of processing based on the characteristics of each individual zone. Moreover, the probability of non-optimal intensification due to the simultaneous processing of multiple zones is significantly reduced if you have only one open set of perforations for each processing level. For example, in the case of hydraulic fracturing, the present invention minimizes the likelihood of excessive flushing or insufficient injection of a wedging agent into the fracture. Additionally, in the event of a problem that necessitates a stoppage, the zones to be excited at the top of the well are not at risk because they have not yet been perforated. This contrasts with 40.3 conventional methods of intensification using a sealing ball or coiled tubing, in which all of the c perforations must be punched prior to intensification. In case of failure during intensification with the use of conventional coiled pipes, it is extremely difficult to effectively carry out deviations and ;" excitement in a long interval of ending. In addition, if only one set of perforations is open above the sealing element, the fluid can circulate without the possibility of breaking down into multiple sets

Open perforations above the upper part of the sealing element, as can happen in the usual -I technological operation with the use of coiled pipes. This can minimize or eliminate fluid loss and formation damage when the bottomhole circulation pressure exceeds the formation pore pressure. o Pumping for the entire treatment can be carried out in a single pass in the well, which

Go! leads to a significant reduction in cost compared to other technologies that require multiple 5-hour movements of a communication lead line or other equipment into the well and back between processing levels. - The invention can be used to carry out multi-stage treatments in inclined or horizontal wellbores. Of course, other traditional technologies of deflection in inclined or horizontal wellbores are more promising, taking into account the nature of the transport of the deflecting material by the fluid medium over long intervals, which are usually present in inclined or horizontal wellbores.

If sand falls out during hydraulic fracturing, then according to the invention (F, a method of immediately pumping the fluid from the well, which is in the annular space with the sand, so that the intensification operation can be resumed without removing the coiled pipes and downhole equipment from the well is proposed The presence of a coiled pipe system creates a means of bottomhole pressure measurement after perforating or during intensification operations, based on pressure calculations in the coiled pipe column when the well is stopped (or at low flow rate).

The presence of a system of coiled pipes or conventional component pipes, if they are used as a means of deployment, creates the possibility of injecting fluid into the well independent of the fluid injected into the annular space. This can be used, for example, in such additional 65 Applications as: (a) cleaning the sealing mechanism of the downhole equipment and the hydraulic system channels from the accumulation of wedging agent (which can serve as the cause of the stuck tool) by pumping the fluid into the well at the nominal cleaning rate sealing mechanism and hydraulic system channels; (b) mixing in the well (discussed in more detail below); (c) pouring acid into the well during perforation to help clean the perforation hole and improve communication with the formation; and (d) independent excitation of two zones isolated from each other by a multiplexing sealing mechanism. Essentially, if the pipes are used as deployment means, depending on the specific operations desired and on the specific components of the downhole equipment, the fluid may circulate in the well at all times, either only when the sealing element is actuated, or only when the sealing element is turned off, or when equalization (pressure) channels 7/o Open or closed. Depending on the specific components of the downhole equipment and the specific design of the downhole flow control valves, which may be used, for example, as integral components of equalization channel adapters, circulation channel adapters or hydraulic system channel adapters, the downhole flow control valves can be controlled by a wireline , by actuation hydraulically, by actuation by flow, by actuation by means of the 7/5 "Izazuka", by actuation by means of a sliding clutch, or by means of a multitude of other means known to specialists in the field actuation of well flow control valves.

The coiled tubing system also allows for controlled backflow at individual treatment levels to aid in cleaning and gap closure. The flowback can flow up through the annular space between the coiled tubing and the production casing, or alternatively, the flowback can even flow up through the coiled tubing string if excessive proppant backflow is not a problem.

Any commercially available punching system can be used as a punching device.

Among such systems are systems with so-called selective ignition, in which a single unit of perforation contains a plurality of charges or sets of charges for perforating. Each individual set of one or more s g charges for perforating can be controlled remotely and ignited from the surface using electrical, radio, pressure, fiber optics, or other means of actuation. Each set of i) perforating charges has design parameters (number of charges, number of holes per foot, hole size, penetration characteristics) that allow for optimal perforations in the individual area to be treated with the individual level. At the current level of perforator technology with selective ignition, there are perforating systems that are available for sale, which allow you to perforate consecutively approximately from ZO to 40 intervals with a single pass in the well. In advance, it is necessary to choose such a structure and such a size of the perforator that allows punching multiple sets of perforations. The perforators can be located in any location on the downhole equipment, including above or below the mechanical, sealing mechanism, which is installed many times -

Treatment intervals can be grouped based on collector properties, treatment parameters, or equipment limits. After creating each group of intervals (preferably containing approximately 5 to 20 intervals), at the end of the working day (which is often determined by lighting conditions) or when difficulties arise when sealing one or more zones, a packer plug or other mechanical isolation device is preferably used groups of already processed intervals from the next group of intervals, which are subject to processing. One or more packer plugs, which are installed due to selective ignition, in c or partition walls of the crack can be introduced together with the drilling equipment and installed during the completion operation to provide mechanical isolation between the perforated intervals and eliminate the need;" the laying of a separate conductive communication line for the installation of mechanical isolation devices or deflection agents between groups of break levels.

In general, the proposed method can easily be used in production casings from 4-1/2 inches to 7 inches in diameter using existing commercial perforating systems and mechanical, multiple-installation sealing mechanisms. The proposed method can be o used in smaller or larger casing strings when using mechanical sealing mechanisms o many times installed, designed appropriately for the indicated smaller or larger casings

COLUMN - When using selective ignition perforators, each individual perforator may be approximately 2 to 8 feet long and contain approximately 8 to 20 perforating charges placed along the perforator tube at a hole density of 1 to 6 holes per foot, preferably 2 to 4 holes per foot.

According to a preferred embodiment, 15 to 20 individual perforators may be combined into a stack, with the assembled perforator system having a total length of less than approximately 80-100 feet. A system with this full length can easily be inserted into the wellbore using the existing surface

F) systems with a tap and a lubricator. Longer length systems can also be used, but may require the use of additional or special surface equipment, depending on the total number of perforators forming a complete perforating device. It should be borne in mind that in some unique applications, the length of the perforators, the number of charges in one perforator and the density of holes may be greater or less than those indicated above, since the final parameters of the perforating system depend on the specific characteristics of the formation intersected by the wellbore, which has to be excited

To minimize the overall length of the perforator and downhole equipment system, it may be desirable to use a plurality (two or more) of charge carriers uniformly spaced and bonded, welded or otherwise attached to the coiled tubing, or installed below the mechanical sealing mechanism, which is set many times. For example, if it is desired to excite 30 zones, when each zone is perforated with a 4-foot perforator, a single perforation block will have a total length of about 130 feet, which is impractical for surface control. Alternatively, two perforating units mounted opposite each other on coiled tubes may be used, each unit containing 15 perforators, with

This has an overall length of approximately 75 feet, allowing for easy surface control with existing crane and lubricator systems.

An alternative version of the construction of the perforator or perforators involves the installation of one or more perforators above the mechanical sealing mechanism, which is installed many times.

Two or more separate perforation blocks are used, fixed so that the charges are oriented in / about the direction of removal from the components of the downhole equipment or from the coiled pipes. A single block with more densely loaded charges can also be used, and the ignition mechanisms provide simultaneous ignition of only one subset of charges in a given interval, possibly all charges with one given phase orientation.

Although the perforating device described in this embodiment uses remote ignition of charges or a fluid jet to perforate the casing and cement casing, alternative perforating devices may be used within the scope of the present invention, including (but not limited to) devices chemical dissolution or cutting devices of drilling and milling, which make it possible to create a path for the flow of fluids between the wellbore and the surrounding formation. In the description of the present invention, the term "perforating device" is used in a broad sense and includes all of the above and other existing devices that can be suspended in the wellbore to actuate charges or other perforating means that can be introduced by with the help of a casing string or with the help of an external relative to the downhole equipment of the device, or with the help of a method of suspension of the downhole equipment.

Downhole equipment may have a downhole motor or other mechanism for generating rotation or torque to actuate mechanical sealing mechanisms that require rotation or torque to actuate. Such a device, in combination with an orientation device and) (for example, with a gyroscope or a compass), allows you to carry out oriented perforation, in which the perforations are made in the preferred direction. Alternatively, if conventional component pipes are used, it is possible to transfer rotation or torque to the well due to direct rotation of the component components of the Pipes using a drive for rotation, which is available on conventional well overhaul installations. Downhole sensors can also be deployed as elements of the downhole equipment for - measuring the conditions in the well (casing joint locator, pressure and temperature sensors, as well as other sensors), which allow real-time control of the parameters of the intensification operation, characteristics collector and/or operational parameters of the well. "

In addition to the mechanical deflection device that is installed many times, other materials and deflection devices may be introduced into the wellbore during treatment, including (but not limited to) packing balls or powdered material such as sand, ceramic material, wedging filler, salt, paraffins, resins or other organic and inorganic compounds; or alternative fluids, such as viscosity-increasing fluids, gelling fluids, foam materials, or other chemically generated fluids or other injectable deflection agents. Additional material with deviation c can be used to reduce the processing time of intensification by reducing the number of settings of the mechanical deviation device, however, while maintaining the possibility of deviation in multiple zones. ;" For example, in a 3,000-foot interval where individual zones are treated at nominal 100-foot intervals, it may be desirable to use a mechanical deflection device that many times

Installed, working in increments of 500 feet up the wellbore, then deflecting -I each of the six levels with a deflection agent carried by the treatment fluid. Alternatively, the input restriction technique can be used for multiple intervals when it is desired to process a subset of a large interval. Each of these possibilities lowers the number

Go! mechanical settings of the mechanical deflection device and possibly increases its effective durability.

If a column of pump-compressor pipes is used as a means of deployment, then the pipes allow - deployment of downhole mixing devices and the use of downhole mixing technology. More precisely, a string of pump-compressor pipes can be used to pump chemicals into the well and then through the hydraulic channels into the downhole equipment, followed by mixing with the fluid medium, which is pumped into the pipes through the annular space of the production casing string. For example, during hydraulic fracturing, it may be desirable to inject nitrogen or carbon dioxide into the well pipes and mix them in the well with the formation fluid so as (F) to obtain a return flow with nitrogen or carbon dioxide. The described method and device can be used to process vertical, inclined or horizontal wellbore shafts. For example, the invention proposes a method of exciting a set of vertical (or almost vertical) cracks for crossing horizontal or inclined wellbore shafts. This technology allows cost-effective completion of a set of wellbores from a single work site.

Wells with multiple side branches may also be treated, with the deepest branch treated first, then a plug or bushing inserted to isolate this lowest branch, followed by treatment of the next uphole 65 branch well, then another plug or actuate another sealing sleeve to isolate this branch; and repeat the process to process the desired number of branches in one wellbore.

If selective ignition perforators are used, although it is desirable to treat the maximum number of intervals, the use of short perforators (eg, 4 feet or less) will in some cases limit well performance by creating an increased pressure drop in the sections closest to the wellbore collector, compared to the use of longer perforators. Well productivity may be similarly limited if only a short interval (eg, 4 feet or less) is perforated using an abrasive jet. At the same time, the probability of excessive backflow of the wedging agent also increases, which leads to a decrease in the efficiency of intensification. Backflow should preferably have a controlled flow rate to limit potential backflow of wedging agent. Depending on the intensity of the backflow, a wedging agent with a polymer coating or alternative configurations of perforators can be used to increase the efficiency of the intensification.

In addition, if the pipes or cable are used as deployment means, to mitigate the potential for unwanted erosion from the wedging agent on the pipes or cable when the media with the wedging agent is directly impacted when it is injected into the lateral outlet pumping channels, the wellhead may be an "isolation device" is formed. Such an isolation device may have a flange connected to a short length of pipe that is inserted down the center of the wellhead, several feet below the injection channels. Downhole equipment and pipes or cable are passed inside the pipe of the isolation device. At the same time, the pipe of the isolation device deflects the wedging agent and isolates the pipes or cable from the direct impact of the wedging agent. The indicated isolation device has a pipe of the appropriate diameter, which allows for the free passage of slaughtering equipment and pipes or cables of a large diameter. The length of the isolation device is chosen so that in the event of damage, the lower main valve will still remain closed and appropriate dismantling of the wellhead can be done to remove the isolation tool. Depending on the type of fluid media for intensification and the method of injection, an isolation device may not be necessary if there are no problems with erosion. Although industrial testing of isolation devices suggests no i) erosion problems associated with the technology used, there is some risk of erosion damage to the isolation tool tubes due to obstructions during its extraction. When using an isolation tool, it is preferred to maintain the impingement velocity of the erosive fluid with the isolation tool below approximately 180 feet per second, and preferably below approximately 60 feet per second. --

Another concern when using this technology is the premature fallout of sand from the sand carrier during hydraulic fracturing, which can happen with inaccurate measurement of the movement of the fluid during pumping, since it is difficult to initiate the fracture with the help of a fluid with a wedging filler through the next zone to be perforated. It may be desirable to use M.

KSI fluid or other non-gelling fluid or cushioning fluid, instead of a gelling fluid cushion, to better initiate fracturing in the next zone. Pumping at a higher speed of a non-gel-forming fluid between the levels to ensure turbulent washing and sweeping of the casing minimizes the risk of shedding of the "wedging agent". In addition, the emergency perforators, which are provided on the column of the tool, allow you to continue the technological operation after the appropriate waiting time.

Although the options described above are primarily related to the advantages of the proposed method when applied to hydraulic fracturing processes, this does not limit the claimed invention, which can be used in any situation in which it is advantageous to perforate and performance of other well operations with one pass in the wellbore. Despite the fact that the preferred variant -I of the implementation of the invention has been described, it is absolutely clear that changes and other additions can be made to it by specialists in this area, which, however, do not go beyond the scope of the following claims. for

Claims (1)

The formula of the invention is 1. A method of perforating and processing a set of intervals of one or more underground formations intersected by a wellbore, which includes the following operations: (a) deployment of the drilling equipment using a deployment tool inside the wellbore, in which the drilling equipment has a device for perforating and sealing mechanism; (B) installation of drilling equipment in a given position inside the wellbore using (F) a depth control device; GI (c) use of a perforating device to perforate the interval; (4) activating the sealing mechanism to create a hydraulic seal in the wellbore; in (f) pumping the processing fluid into the wellbore and into the perforations created by the perforating device without removing the perforating device from the wellbore; () releasing the sealing mechanism; (94) repeating operations (5)-() for at least one additional interval of one or more underground formations. 65 2. The method according to claim 1, in which the deployment means is selected from the group consisting of a communication wire, a wire rope, and a cable. 3. The method according to claim 1, in which the means of deployment is a column of pump-compressor pipes. 4. The method according to claim 3, in which the column of pump-compressor pipes is selected from the group that includes coiled pipes and component pipes. 5. The method according to claim 1, in which the drilling equipment is installed in a predetermined position inside the wellbore using a depth control device selected from the group consisting of a casing joint locator and a measurement system located on the surface. 6. The method according to claim 1, in which the device for perforating is a shooting perforator with selective ignition, containing a plurality of sets having one or more cumulative charges for /o perforating, and each of the sets is made with the possibility of individual control and actuation using an electrical or optical signal transmitted through a cable deployed in the wellbore. 7. The method according to claim 1, in which the sealing mechanism is a packer that is installed many times. 8. The method according to claim 1, in which the processing fluid is selected from the group consisting of an acid solution, a 7/5 organic solvent, a wedging material suspension, and a transporting fluid. 9. The method according to claim 1, which additionally includes a deployment operation performed before the release of the sealing mechanism of at least one deflection agent in the wellbore to block the additional flow of the processing fluid in the perforation. 10. The method according to claim 9, in which the deflection agent deployed in the wellbore is selected from the group consisting of powders, gels, viscous fluids, foam materials and sealing balls. 11. The method according to claim 1, in which the sealing mechanism is actuated by hydraulic pressure transmitted from the surface through the folded hose. 12. The method of claim 1, wherein the sealing mechanism is actuated to establish a hydraulic seal below the perforated interval. high school 13. The method according to claim 1, in which the device for perforating is actuated by hydraulic pressure transmitted from the surface through the folded hose. 14. The method according to claim 1, in which the device for perforating is actuated due to hydraulic pressure transmitted from the surface through the wellbore. 15. The method according to point C, in which the device for perforating is activated due to the hydraulic pressure that is transmitted from the surface through the column of pump-compressor pipes. 16. The method according to claim 1, in which the drilling equipment is moved to another position inside the wellbore before activating the sealing mechanism. co 17. The method according to clause 3, in which the perforating device is a jet cutting device, in which a fluid is used, pumped down into a column of pump-compressor pipes to establish a hydraulic connection between the wellbore and one or more intervals of one or more - underground formations. 18. The method according to point 3, in which the fluid for treatment is pumped down into the annular space between the column of pump-compressor pipes and the wellbore. 19. The method according to claim 18, in which the fluid for processing is also pumped down into the column of pump-compressor pipes through the channels in the punching equipment and further into the perforation. with p 20. The method according to claim 18, in which the second fluid for processing is pumped down into the column of pump-compressor pipes through the channels in the punching equipment and further into the perforation. ;" 21. The method according to claim 20, in which the second processing fluid is nitrogen. 22. The method of perforating and processing a set of intervals of one or more underground formations intersected by the wellbore, which includes the following operations: -And (a) deployment of the downhole equipment using the means of deployment selected from the group that includes the conductive line of communication, wire rope and cable, inside the wellbore, and the indicated drilling equipment has a device for perforating and a sealing mechanism; Go! (c) using a perforating device to perforate the interval; (c) activating the sealing mechanism to create a hydraulic seal in the wellbore; - (4) pumping of processing fluid into the wellbore and into perforations created by the perforating device without removing the perforating device from the wellbore; (f) releasing the sealing mechanism; (0 repetition of operations (5)-(-ez) for at least one additional interval of one or more underground formations. 23. The method according to claim 22, in which the drilling equipment is installed in a given position inside the barrel (F, well) using a depth control device selected from the group, which includes a locator of couplings and casing joints and a measurement system located on the surface. 24. The method according to claim 22, in which the device for perforating is a shooting perforator with selective ignition, containing a plurality of sets having one or more cumulative charges for perforating, and each of the sets is made with the possibility of individual control and actuation by using an electrical or optical signal transmitted through a cable deployed in the wellbore. 25. The method according to claim 22, in which the sealing mechanism is a packer that is installed multiple times. 65 26. The method according to claim 22, in which the processing fluid is selected from the group consisting of an acid solution, an organic solvent, a wedging material suspension, and a transporting fluid. 27. The method according to claim 22, which additionally includes a deployment operation performed before releasing the sealing mechanism of at least one deflection agent in the wellbore to block additional flow of processing fluid in the perforation. 28. The method according to claim 27, in which the deflection agent deployed in the wellbore is selected from the group consisting of powders, gels, viscous fluids, foam materials and sealing balls. 29. The method according to claim 22, in which the sealing mechanism is actuated by hydraulic pressure transmitted from the surface through the folded hose. 30. The method according to claim 22, in which the device for perforating is actuated by hydraulic pressure 7/0 transmitted from the surface through a folded hose. 31. The method according to claim 22, in which the perforating device is actuated by hydraulic pressure transmitted from the surface through the wellbore. 32. The method according to claim 22, in which the drilling equipment is moved to another position inside the wellbore before activating the sealing mechanism. 33. The method of claim 22, wherein the sealing mechanism is actuated to establish a hydraulic seal below the perforated interval. 34. Intensification system for use in perforating and processing multiple intervals of one or more underground formations intersected by the wellbore, containing the following components: (a) fluid medium for processing; (B) deployment means selected from the group consisting of a wireline, a wire rope, and a cable deployed within the wellbore; (c) downhole equipment made with the possibility of deployment in the wellbore with the help of a deployment tool and which has at least one device for perforating, which allows sequential perforation of a plurality of intervals, and at least one sealing mechanism, while the downhole equipment is made with the possibility of installation to a given position inside the wellbore, which allows the perforating device and the sealing mechanism to be activated; i) (4) and the sealing mechanism is made with the possibility of creating a hydraulic seal in the wellbore and with the possibility of depressurizing the hydraulic seal, which allows repositioning the drilling equipment to another position inside the wellbore, due to which the possibility of processing each of the set of intervals to be processed is ensured fluid for processing separately from other processing intervals. -- 35. Intensification system for use in perforating and processing multiple intervals of one or more underground formations intersected by the wellbore, containing the following components: (a) fluid medium for processing; - (B) means of deployment deployed inside the wellbore; y- (c) drilling equipment, made with the possibility of deployment in the wellbore with the help of a deployment tool and holding at least one device for perforating, which allows sequential perforation of a plurality of intervals, and at least one sealing mechanism, while the drilling equipment is designed with the possibility of installation in a given position inside the wellbore using a "depth control device that allows you to activate the perforating device and the sealing mechanism; in c (4) and the sealing mechanism is made with the possibility of creating a hydraulic seal in the barrel . of the well and with the possibility of depressurizing the hydraulic seal, which allows you to move the drilling equipment to another position inside the wellbore, due to which it is possible to treat each of the set of intervals to be treated with a fluid for treatment separately from other treatment intervals. -I 36. A device for use in perforating and processing a plurality of intervals of one or more underground formations intersected by a wellbore, containing the following components: o (a) punching equipment adapted for deployment in the wellbore by means of Go! a deployment selected from the group consisting of a communication line, a wire rope and a cable, and 5p holding at least one perforating device designed to sequentially perforate a plurality of intervals, and at least one sealing mechanism; c B) and the sealing mechanism is made with the possibility of forming a hydraulic seal in the wellbore, and with the possibility of depressurizing the hydraulic seal, which allows repositioning the drilling equipment to another position inside the wellbore, due to which the possibility of B processing each of the set of intervals to be processed separately from other processing intervals. 37. The device according to claim 36, which additionally contains a means of controlling the depth, designed to install the downhole (F, equipment) in a given position in the wellbore and selected from the group consisting of a locator of coupling joints of the casing string and a measuring system located on the surface . 38. The device according to claim 35, in which the sealing mechanism is a packer that is installed multiple times. in 39. The device according to claim 36, in which the perforating device is a firing perforator with selective ignition, containing a plurality of sets having one or more cumulative charges for perforating, and each of said sets is made with the possibility of individual control and actuation using an electrical signal transmitted through a conductive communication line deployed in the wellbore. 65 40. The device according to claim 36, in which the perforating device is actuated by hydraulic pressure transmitted from the surface through said wellbore. 41. A device for use in perforating and processing a plurality of intervals of one or more subterranean formations intersected by a wellbore, comprising the following components: (a) drilling equipment adapted to be deployed in the wellbore by means of the deployment means and to be installed in a predetermined position within a wellbore using a depth control device and holding at least one perforating device designed to sequentially perforate a plurality of intervals and at least one sealing mechanism; (B) at the same time, the sealing mechanism is made with the possibility of forming a hydraulic seal in the specified wellbore and with the possibility of depressurizing the hydraulic seal, which allows repositioning the 7/0 drilling equipment to another position inside the wellbore, due to which the possibility of processing each of the set appears processing intervals separately from other processing intervals. 42. The device according to claim 41, in which the deployment means is a column of pump-compressor pipes. 43. The device of claim 41, wherein the perforating device is actuated by hydraulic pressure transmitted from the surface through said wellbore. 44. The device according to claim 42, in which the device for perforating is actuated by means of hydraulic pressure transmitted from the surface through a column of pump-compressor pipes. 45. The device of claim 42, wherein the perforating device is a jet cutting device that uses a fluid pumped down the tubing string to establish hydraulic communication between the wellbore and one or more intervals of one or more underground formations . 46. The device according to claim 42, in which the column of pump-cum-compressor pipes is selected from the group consisting of coiled pipes and folded pipes. 47. The device according to claim 41, in which the means of deployment is selected from the group consisting of a conductive communication line, a wire rope, and a cable. with 48. The device according to claim 41, which additionally contains a means of controlling the depth, is intended for installation of drilling equipment in a given position in the wellbore and is selected from the group consisting of a locator and) sleeve connections of the casing string and a measuring system located on the surface. 49. The device according to claim 41, in which the sealing mechanism is a packer that is installed multiple times. 50. The device according to claim 41, in which the perforating device is a firing perforator with selective ignition, containing a plurality of sets having one or more cumulative charges for perforating, and each of said sets is made with the possibility of individual control and - drive into action with the help of an electrical signal transmitted through a conductive communication line deployed in the wellbore. 51. The device according to claim 41, in which the device for perforating is actuated with the help of hydraulic "335 pressure transmitted from the surface through the indicated wellbore. Cha 52. A device for use in perforating and processing a plurality of intervals of one or more underground formations intersected by a wellbore, containing the following components: (a) drilling equipment having at least one device for perforating, designed for consecutive perforation of a plurality of intervals, at least one mechanism compaction and at least one « 70 tractor device; in c (B) and the tractor device is adapted to move the drilling equipment to different positions in the wellbore; and?" (c) at the same time, the sealing device is adapted to form a hydraulic seal in the wellbore and allows the hydraulic seal to be depressurized, which provides the ability to move the Downhole Equipment to another position inside the specified wellbore, due to which - AND the possibility of processing each of the set of intervals to be processed separately from other processing intervals. пи 53. The device according to claim 52, which additionally contains a means of controlling the depth, is intended for installation of drilling equipment in a given position in the wellbore and is selected from the group consisting of a locator of MuUft connections of the casing string and a measuring system located on the surface. - 54. The device according to claim 52, in which the sealing mechanism is a packer that is installed many times. c 55. The device according to claim 52, in which the perforating device is a firing perforator with selective ignition, containing a plurality of sets having one or more cumulative charges for perforating, and each of said sets is made with the possibility of individual control and actuation using an electrical signal transmitted through a conductive communication line deployed in the wellbore. F) 56. The device according to claim 52, in which the device for perforating is actuated by means of hydraulic ka pressure transmitted from the surface through the specified wellbore. 57. A method of perforating and processing multiple intervals of one or more underground formations that are crossed by a wellbore, which includes the following operations: (a) deployment inside the wellbore of drilling equipment containing a device for perforating, a sealing mechanism and at least one means of pressure equalization; (c) using a perforating device to perforate an interval in one or more underground formations; 65 (c) activating the sealing mechanism to form a hydraulic seal in the wellbore; (4) pumping the processing fluid into the wellbore and into the perforation created by the perforating device without removing the perforating device from the wellbore; (e) pressure equalization between the sections of the wellbore above and below the sealing mechanism with the help of at least one means of pressure equalization; () releasing the sealing mechanism; (94) repeating operations (5)-() for at least one additional interval of one or more underground formations. 58. The method according to claim 57, in which the drilling equipment is reset to another position in the wellbore and the sealing mechanism is actuated to form a hydraulic seal below the perforated interval. 70 59. A method of perforating and processing a plurality of intervals of one or more underground formations intersected by a wellbore, containing the following operations: (a) deployment inside the wellbore of drilling equipment containing at least one device for perforating and at least one sealing mechanism, and the device for perforation, they are installed below the sealing mechanism; (B) using at least one perforating device to perforate an interval in one or more underground formations; (c) activating at least one sealing mechanism to form a hydraulic seal in the wellbore; (4) pumping the processing fluid into the wellbore and into the perforation created by the perforating device without removing the perforating device from the wellbore; (f) releasing the sealing mechanism; (0 repetition of operations (5)-(-ez) for at least one additional interval of one or more underground formations. 60. The method according to claim 59, in which the device for perforating does not have a channel for flushing fluid medium. 61. The method according to any of claims 59-60, in which the drilling equipment is repositioned in i) the wellbore and the sealing mechanism is actuated to form a hydraulic seal below the perforated interval. 62. The method of perforating and processing a set of intervals of one or more underground formations intersected by a wellbore, and the set of intervals includes the deepest specified interval and successively smaller specified intervals, containing the following operations: -- (a) deployment inside the wellbore pitting equipment, containing a device for co-perforating and a sealing mechanism, and the device for perforating is installed below the sealing mechanism; (B) using a perforating device to perforate the deepest part of a specified interval of one or more underground formations; (c) pumping the processing fluid into the wellbore and into the perforation created in the deepest interval by the perforating device without removing the perforating device from the wellbore; "(4) installation of drilling equipment in a given position in the wellbore and use of the perforating device in order to perforate the next successively finer given interval of one or more underground formations; ;" (f) changing the position of the drilling equipment in the wellbore and activating the sealing mechanism for hydraulic isolation of perforations created in the next successively smaller specified interval from the perforated deepest specified interval; -And () pumping of fluid for processing into the wellbore and in the perforation, created in the next successively smaller set interval using the perforating device, without removing the perforating device from the wellbore; Go! (9) releasing the sealing mechanism; (n) repeating operations (4)--c9) for at least one additional successively finer specified interval of one or more underground formations, and the perforations formed in at least one additional successively finer specified interval are hydraulically isolated from the perforated intervals below. 63. A device for use in perforating and processing a plurality of intervals of one or more subterranean formations intersected by a wellbore, holding drilling equipment adapted for deployment in the wellbore with the help of a deployment device and holding (F, at least one device for perforating, intended for sequential perforation of multiple intervals, at least one sealing mechanism and at least one means of pressure equalization, and the sealing mechanism is made with the possibility of forming a hydraulic seal in the wellbore, the means of pressure equalization is made with the possibility of pressure equalization between the sections of the wellbore above and below the sealing mechanism, and the sealing mechanism is further configured to depressurize the hydraulic seal to allow the downhole equipment to be moved to another position in the wellbore to allow each of the plurality of intervals to be treated separately in from other processing intervals. 65 64. A device for use in perforating and processing multiple intervals of one or more underground formations intersected by the wellbore, holding the drilling equipment, adapted to be deployed in the wellbore by means of the deployment means, and holding at least one perforating device designed to sequentially perforate a plurality of intervals, and at least one sealing mechanism, wherein the perforating device is installed below the sealing mechanism; the sealing mechanism is made with the possibility of creating a hydraulic seal in the wellbore and with the possibility of depressurizing the hydraulic seal to ensure the movement of the drilling equipment to another position in the wellbore, for the possibility of processing each of the plurality of intervals separately from other processing intervals. 70 65. The device according to claim 64, in which the perforating device does not have a channel for flushing fluid. 6) (ee) «- (ee) « and - - and? -i sh" (ee) - 70 IR e) ime) 60 b5